- Home
- Conferences
- Conference Proceedings
- Conferences
PGCE 2010
- Conference date: 29 Mar 2010 - 30 Mar 2010
- Location: Kuala Lumpur, Malaysia
- Published: 29 March 2010
100 results
-
-
Recent Developments and Future Challenges in 3D Reservoir Modelling
More LessThe most significant recent developments and (indeed) future challenges in 3D reservoir modelling are related to two main topics: 1. The ability of the 3D models to describe realistic structural and stratigraphic geometries. 2. The integration of data from a wide variety of sources including; well, seismic and production data. MODELLING REALISTIC GEOMETRIES 3D structural modelling of large and complex fields has remained a bottleneck in the 3D reservoir modelling workflow. Nevertheless there have been large improvements in the ability of modelling algorithms to describe complex structural geometries in strongly extensional and compressional regimes, and around salt domes. Many of these advances required a major concept change from describing faults using pillars to a less constrained pillar-free representation in the 3D model. Modelling of realistic stratigraphic architecture has also seen significant advances in recent years due to enhancement of object modelling algorithms and the introduction of “Multi-Point” Statics (MPS). There is still a need however for further development of facies modelling algorithms to capture realistic depositional and diagenetic geometries. Outcrop analogues should be used more actively for designing realistic algorithms and for constraining the input parameters to the models. DATA INTEGRATION One of the main aims of 3D modelling is to utilise all available data and interpretations in a consistent manner. Recent developments have seen much improved use of horizontal well data in the structural model construction, and increasing application of seismic data in property modelling. Two important integration themes are still in their infancy and are receiving increased focus. The first involves the incorporation of 4D seismic feedback into the static and dynamic models. The second involves the active use of dynamic (history) data in the static model (“the Big Loop”). The integration of these data types will become more commonplace during the next few years and will contribute to improved 3D reservoir models and subsequently to better reservoir management of “Challenging Discoveries”.
-
-
-
Removing Non-Stationary Artifacts from Seismic Velocity Data Sets by M-Factorial Kriging
Authors Cedric Magneron and Jacques Deraisme and Matthieu BourgesSeismic velocities are often polluted by acquisition or processing artifacts which should be identified and removed as they may have a non-negligible impact on subsequent processing such as migration, stack, angle analysis (AVO), litho-pressure analysis, time to depth conversion, etc. Artifacts encountered in seismic velocity data sets can be parted into: § acquisition artifacts, mainly footprint effect § processing artifacts such as white noise due to software picking resolution, inline oriented picking effect, smoothing operator imprint, etc. Factorial kriging is a geostatistical filtering technique developed by Georges Matheron in 1982, which enables to extract artifacts from a velocity data set. Factorial kriging relies on a simple additive model where the spatial variable under study is modeled by a random function, V(x), which is parted in terms of independent factors: V (x) = V1 (x) + V2(x) + …
Artifacts extraction issues can be easily handled into the framework of this model, as far as the artifacts part of a data set can be considered independent of a complementary geological part: V (x) = VARTIFACTS (x) + VGEOL (x) In such a way, factorial kriging, by estimating VGEOL(x), allows to filter out the artifacts component VARTIFACTS (x) of the data set. During recent years in the petroleum industry, factorial kriging has been applied with success for removing artifacts from seismic velocity data sets. Nevertheless it appeared sometimes limited when faced with non-stationary artifacts, i.e. of intensity or geometrical characteristics varying spatially. M-GS (Moving-GeoStatistics) is an innovative technology which is fully dedicated to the local optimization of parameters involved in variogram-based models. By optimizing spatially varying model parameters, M-GS guarantees a better adequacy between geostatistical model and data. This paper demonstrates how M-GS technology, combined with factorial kriging process, provides an optimal way for extracting properly non-stationary artifacts from velocity data sets. The computation of local structural parameters related to the artifacts part of data, as well as the gain in quality obtained by this approach, are illustrated on a real migration velocity cube.
-
-
-
Middle Permian Fluvial System in the Arabian Peninsula: The Gharif Formation Outcrops in Huqf Area, Central Oman
More LessThe upper Plaeozoic sediments in east and central Oman are comprised dominantly of clastic sequences of the Haushi Group and host major hydrocarbon reservoirs in central Oman basins. The basal part of the upper Paleozoic clastic sequence represents 3rd episode of Gondwanan glaciation in the Arabian Peninsula and is composed of glacial and glacio-fluvial deposits of the Al-Khlata Formation, overlain by fluvial dominated Gharif Formation. This clastic sequence is widely distributed in subsurface of the Oman
interior basins and surrounding parts of the Arabian Peninsula such as in Saudi Arabia and U.A.E. These rocks are well exposed in outcrops in eastern and central parts of the Oman desert between Huqf and Duqm areas. This study deals with the depositional system of the clastic Gharif Formation exposed in isolated outcrops in central Huqf area by describing its lithofacies association. The exposed thickness of the Gharif Formation around famous pinnacle structures is about 60m and it is composed of interbedded sandstone, siltstone and clay. The sandstone facies on average constitute 10m thick multistoried sequences which are composed internally of 2-3m thick and 100s of metres across vertically and laterally amalgamated sandstone bodies. Individual sandstone bodies are identified by the presence of lag deposits or laterally pinching thin clay beds. The sandstone is both planar and trough cross-bedded with cross-sets on average 30cm thick exhibiting a dominant paleoflow direction towards NW (N280-300°). Compositionally the sandstone is comprised of coarse grain to pebbly, loosely cemented, white to buff colour, arkosic sand. Silicified plant fragments are commonly distributed in sandstone, particularly in its upper part. These sandstones are interpreted to have
been deposited by low sinuosity ephemeral streams on a braid plain. Interbedded clays and siltstones are red, mottled and extensively bioturbated due to root burrows. Thickest red clay sequence at the base of the described section is 15m thick interbedded with occasional thin fine grain sandstone beds and carbonaceous gray shale. These fine grain sediments were deposited on flood plains as crevasse splay deposits during episodes of channel evulsions. In the uppermost part of the section, a number of dark gray to black carbonaceous clay bed with plant matter are interbedded with sandstone and red clay/siltstone indicating development of swampy conditions associated with coastal conditions in the uppermost part of the formation. Middle Permian time in the Huqf area of the Arabian Peninsula was dominated by major braided river system which changed upsection into coastal setting followed by a major sea transgression depositing marine succession of the Khuff Formation. Laterally and vertically amalgamated thick sandstone sequences dominated by superimposed planar and trough cross-bedding were deposited by shallow multichannel flows
-
-
-
Faulting and Clay Gouging in Neogene Clastics of the Lambir Fm., Sarawak
Authors Franz L.Kessler and Titus Murray and John JongThe new coastal Miri-Bintulu road intersects, near the Tusan junction some 40 km South of Miri, a series of normal faults, vested in a 80 deg dipping clastic sequence located near to the core of the complex Lambir Anticline are observed. The outcrop shows beautiful examples of clay gouging, fault drag and concussion. Faults have been measured and correlated (Figs. 1, 2). Clay gouging indicate a correlation between gouging thickness and fault throw (Fig. 3). Development of fault rock (Fig. 4) is noted within
competent (hence brittle) sandstone units, regardless of hanging wall or footwall position, whereas clay bodies react ductile and show fault drag. The authors intend to further investigate the clay gouge sealing capacity, calibrate the outcrop data with modeling packages such as FaultRiskTM, and approach industry players for sponsorship.
-
-
-
D35 Field: Integrated Approach to Manage Challenging Reservoir Characterization Study and Impact of the Revised Geological Model for Ultimate Recovery
The structural complex of D35 Field presents a variety of challenges to geoscientists and engineers. Located in the Balingian Province offshore Sarawak, it was discovered in 1983 and has become one of the major oil-producing fields in the area (Figure 1, Location Map). The structural complexity, resulting in compartmentalization of the reservoir is attributed to the collision and wrenching episodes between the Central Luconia Province to the north, and the onshore Tinjar Province and the Rajang Fold-Thrust Belt to the south (Mazlan Madon & Peter Abolins, 1999). In addition, Swinburn (1994) reported that the western part of the Balingian province, where D35 is located, was subjected to a folding, faulting, and erosion, thus affected the sedimentation processes throughout reservoir sands of Cycle I to Cycle IV. Because of this complexity, for the past 25 years, the interpretation on depositional setting of the reservoir sand has changed few times. In 1984 when with limited data; it was interpreted as coastal plain with
fluvial channel reservoir. In 1988, a ‘Mississippi’ delta interpretation was introduced before it was replaced by fluvioestuarine environment in 1994. In 2003, the interpretation was revised back to a fluvial environment with a series of stacked and isolate channels envisaged. The current study in 2009, however, has established a coastal sedimentary setting as the environment to be more realistic based on these new findings are the results of the comprehensive and integrated undertaking in Geology, Geophysics,
Petrophysics, and Petroleum Engineering. This paper focuses on the prolific sands of Cycle II and Cycle III reservoirs. The geological studies encompass application of sequence stratigraphy in well log correlations, and detail core analyses include sedimentological facies descriptions, ichnofacies study, coal petrology, and biostratigraphy. The Cycle II depositional setting (Figure 2) has been established as the coastal and related estuarine deposit rather than stacked channel deposits previously interpreted. The prograding units are sheet with thick and widespread as shown in figure. Cores recovered from the unit show evidence of marine influence such as burrows of Ophiomorpha and sedimentary structures typical to the coastal deposits. Analysis of the trace fossil assemblages demonstrates a variety of sub-environments, from a marine influenced lower coastal plain to a fully marine environment. The Cycle III depositional setting (Figure 2) has been established as the coastal longshore bars deposited in a transgressive system tract. Log correlations show the stacking pattern of the parasequences as retrogradational (Figure 3). As in Cycle II, cores from the unit show evidences of marine influence, as opposed to fluvial, interpretation used in previous models. Sandstone thicknesses derived from geostatistical inversion work show northwest-southeast trending sand bodies (Figure 4) consistent with the longshore bar environment interpretation. These new findings translate to widely distributed sands in the established Cycle II and Cycle III, in contrast to the channelized and stacked sand patterns in the previous model. These have given positive impacts on the current hydrocarbon volumes and potential exploration prospects. The findings also support the assessment of leads in exploration potentials in Cycle II and Cycle III.
-
-
-
Integrating Geophysical Technologies for 4D Seismic Pressure-Saturation Analysis in Angsi Field
PETRONAS Research has recently embarked on a study to determine and understand pressuresaturation variations in the Angsi field through the use of 4D seismic technology. Changes in hydrocarbon pressure and saturation due to production produce noticeable changes in amplitude response. 4D seismic, or the use of repeated 2D/3D seismic surveys as a function of calendar year enables detection of 4D signal indicative of pressure or saturation changes. The Angsi field is located in the Malay Basin approximately 106 miles offshore Peninsular Malaysia. Angsi is a joint venture development between PCSB and ExxonMobil Exploration & Production Malaysia (EMEPMI), with the field being operated by PCSB. The major oil bearing reservoirs are the I-35 and I-68 sands with several gas bearing reservoirs in the I and K sands. Determining pressure-saturation variations involve integrating several geophysical technologies working in close ties with the reservoir engineers, that is, supporting petroleum geo-engineering. These technologies include well-synthetic-seismic correlation, Rock Physics, Production Scenario Seismic Modeling at selected injector/producer wells, 2D/3D seismic modeling, 4D AVO Modelling/Interpretation and correlating seismic attributes with the engineering data, pressure history and saturation measurements. We are primarily motivated by other previous work which focuses on the use of Time-Lapse (4D) AVO data to decouple pressure and saturation variations taking note that AVO attributes of Intercept and Gradient may not be suitable, as they conflict with the small angle (θ) assumption in the data. We should study and use the seismic attributes which respond differently to reservoir changes in pressure and saturation. Figure 1 shows a rock physics representation in the Angsi field indicating the oil response separation from the background. An AVO modeling study was conducted to understand and compare the predicted AVO responses at the reservoir sands with the response observed on the base-monitor seismic data. A seismic inline showing the Angsi I35 main channel is correlated with the corresponding seismic channel model for a structural image analysis generated using actual acquisition parameters applied on the Angsi field. Figure 2 shows seismic attributes extraction results of the I35 reservoir channel. The extraction was performed on the base and monitor seismic data to study the resulting differences. These attributes and difference maps can then be correlated/integrated with pressure and saturation maps for interpretation of the 4D effects. We initially select the two (2) attributes of P- and S-Impedances that were earlier used by Tura and Lumley (1999). These attributes respond differently to reservoir changes, P-impedance changes being more sensitive to saturation changes, while S-impedance changes sensitive to pressure changes. These two AVO attributes are indeed very ‘robust’, being less sensitive to noise in the gather data, and could be computed by simple AVO inversion method.
Improving reservoir monitoring through the effective use of 4D Seismic Pressure-Saturation discrimination methods will enable us to more accurately locate bypassed oil and therefore, increase reserves. In addition, 4D seismic will minimize costs due to infill drilling by optimally locating development wells.
-
-
-
Linapacan Limestone Fracture – Illuminated Through Seismic, a Case Study
Authors J.P. Micu, J.B. Barajas and V.W.T. Kong and Pang Ching MeiThe West Linapacan field is situated 60 kilometers offshore Palawan Island, The Philippines. This field was discovered in 1990, with some production during a 3 year period. It was subsequently shut-in due to economics, which were exacerbated by increasing water production. The West Linapacan A and B structures are NW/SE trending, fault bounded anticlines. West Linapacan B is approximately 7.6 km to the ESE of the 'A' structure. Both are comprised of Upper Eocene to Lower Miocene age fractured limestone. In order to better understand the distribution of fractures within the Linapacan limestone a geophysical study was commissioned to characterize the density and the predominant alignment of the fracture system. 3D seismic data covered the West Linapacan field. The seismic data was recently reprocessed, with angle sub-stacks generated as part of the reprocessing exercise. The availability of the seismic angle substacks made possible the use of the simultaneous seismic inversion technique to compute for multiple rock physics data cubes such as acoustic impedance, shear impedance, and density. Fracture clusters within hard rock such as limestone and granite are generally characterized by a lower acoustic impedance of the local area but do not provide sufficient information on the fracture azimuthal trends. Productive fractures are considered to be longitudinally connected, and these would be better imaged by shear component seismic data. The computation of shear seismic responses by means of the simultaneous seismic inversion process provides a practical alternative to the prohibitive cost of acquiring shear seismic data. The shear-rich seismic based calibrated data is then used in the Ant-Tracking procedure where fracture, faults and vugs within the limestone body in a 3D manner. The Ant-Track results show the fracture cluster density as well as the predominant fracture strike orientation. FMS data acquired in one of the West Linapacan wells affirmed the fracture strike orientation sampled in the well bore.
-
-
-
CSEM Survey in Deepwater Sarawak: Challenge and Learning Continues
3D CSEM data has been acquired in deepwater Sarawak by EMGS for prospect ranking and derisking. 3D inversion and post inversion modelling show complexity of the survey area. By integrating available geological and geophysical data with CSEM data, geologically and physically sound models could be built. Thus, CSEM data plays an important role in complementing other geological and geophysical data, for example seismic and well log data, in exploring and evaluating new prospects.
-
-
-
MAZ Depth-Velocity Modelling and Imaging with Azimuthal Anisotropy
Authors S. Birdus, E. Angerer and I.Abassi and K.ShamisIn recent years we have observed rapid developments in wide- and multi-azimuth seismic data acquisition and processing; in many regions such techniques are becoming more and more common. They dramatically improve illumination below complex overburden and allow geophysicists to study additional rock properties associated with azimuthal anisotropy. In order to fully utilize all the benefits of wide-azimuth seismic data some new challenges have to be solved at processing stage, one of them is depth-velocity modelling and imaging with azimuthal velocity anisotropy. The Middle Eastern onshore field of the current study is a fractured reservoir producing from rotated basement fault blocks with considerable structure. Moreover, the overburden contains several salt domes. A full azimuth 3D seismic survey was acquired to guarantee optimum illumination, to achieve detailed imaging and accurate positioning for the structure below the salt and to estimate stress and fracture related azimuthal anisotropy throughout the field. In order to meet these objectives a prestack depth migration that incorporates azimuthal anisotropy is required. Here, we will discuss issues associated with azimuthal anisotropic depthvelocity modelling and depth imaging.
-
-
-
Seismic Data Conditioning of Partial Stacks
Authors E. Efthymiou, H. Morris and P. Wild and M.KemperAVO analysis is increasingly becoming part of the everyday workflow, however it is often found that existing data sets require further conditioning in order to extract accurate reservoir properties within the zones of interest. We present a systematic workflow which incorporates the understanding taken from the well based AVO analysis to align the seismic data to the true AVO signal of the earth. The following steps were key to the analysis; Zero Phasing, Spectral Balancing,Time Alignment; and Offset Balancing.
Coarse seismic velocities often cause misalignement of offset stacks and review of the partial stacks presented here shows that there is not only subtle time misalignments but also frequency differences and phase issues that cause the well response to be out of sync with the seismic. Small misalignments and NMO stretching will bias any quantitative interpretations causing the inputs to AVO analysis and inversion to be noise dominated. The method used here produces data appropriately compensated for high-fidelity AVO analysis. Compensation for NMO stretch and offset balancing are key to this project. The well based AVO Seismic Data Conditioning approach adopted here corrects for the relative amplitude loss between near and far offsets, often referred to as offset balancing. The seismic data conditioning example used here was successful in improving the quality of the partial stacks without destroying the AVO content. Each step progressively improved the final results of creating an Intercept and Gradient reflectivity, additionally the final partial stacks honour the AVO of the log based synthetics. The wells and the seismic now share the same dynamic range of AVO characteristics as those seen at the wells. Whereas previously we had a noisy gradient reflectivity at the top of the reservoir the improved data now showed characteristics which were more indicative of geological features (Figure 1). Seismic Data Conditioning is more commonly performed on prestack gathers, however it is also applicable to partial stacks as shown here. The methodology for both prestack and partial stacks is very similar and seismic data conditioning of the partial stacks is considered a cost effective alternative to seismic data conditioning of the prestack gathers.
-
-
-
An Interpration of Gravity and Magnetic Data for Hydrocarbon Exploration in the Sirt Basin (Central North of Libya)
More LessGravity and magnetic data for hydrocarbon exploration in the Sirt basin in north central Libya were studied. The study involves analysis of the data to delineate major structures and faults in the study area. The produced Bouguer gravity map shows prominent NW-SE and NE-SW structural/trends. Isostatic residual map for gravity data is characterized by a dominant NW-SE trend in the study area. This is clearly evident in the Isostatic residual map. The main trending anomalies are in the northern and southeastern parts of study area with NW-SE orientation. A strong NW-SE trend is truncated by E-W trending structures in the southeastern and southwestern parts of the area. This is consistent with the change of tectonic zones. The magnetic expression in the northern part of Agedabia trough is characterized by NW-SE trending structures which coincide with late Cretaceous structures of the Sirt basin, while the southern part is characterised by NE-SW trending features which coincide with a late Palaeozoic trend. The northern part of the Agedabia trough is separated from the southern part by a prominent NE-SW lineament that is expressed in both the gravity and magnetic data. It is interpreted as a basement fault, which separates a thicker southern crust from a thinner
northern crust. The high gravity anomaly within the northern part of the Agedabia trough is interpreted as a result of mantle upwelling which caused thinning of the continental crust beneath the northern part of the Agedabia trough. Total horizontal derivative of the gravity and magnetic data generally reflect faults or compositional changes which can be seen to describe structural trends. The central part of the basin can be divided into four zones where the eastern and northern zone shows many short anomalies of NW-SE orientation and the southern zone shows N-S orientation, in the northern zone of the central part shows NWSE orientation trends. In the eastern zone strong NW-SE trends cut with NE-SW changing to E-W trends. The NW-SE structural trends of the Sirt basin are related to the late Cretaceous extensional phase and seem to truncate the other tectonic trends. These structures developed the traps and migration of hydrocarbons during Early Oligocene and Paleocene.
-
-
-
Coil Shooting – Full Azimuth Acquisition with a Single Towed Streamer Vessel
More LessCoil Shooting is a new method for acquiring a full azimuth dataset using a single towed streamer vessel. Conventional towed streamer acquisition collects a very limited range of azimiths, generally less than ten degree’s. Even with this limited azimuth sampling, In areas where the the geology is homogeneous and simple, the target reservoirs are generally still evenly illuminatd by the surface source and receiver geometry. However, in areas where the geology is complex as a result of rugose water-bottom, heavy faulting, steep dipping structure and heterogeneous over-burden, the underltying target reservoirs will be unevenly illuminated. In extreme cases large zones of the target reservoir can be completely un-illuminated with these limited azimuth geometries.
The first commercial coil shooting dataset was acquired off Indonesia in Spetember 2008. In total 157 coils were acquired over a 400 square km area to image two sub-surface structures.
-
-
-
The Role of Elastic Rock Properties Conditioning for Quantitative Interpretation of Seismic Amplitudes in the Sarawak Basin, Malaysia.
More LessData integration is very important for the success of quantitative interpretation project. Well logs, core measurements, reservoir fluid properties, existing geological model and pre-stack/post-stack seismic data need a close-up analysis before integrating for quantitative analysis. Any of the poor quality data set may limit the analysis/interpretation. Limitations of seismic data due to noise, frequency content and imaging issues are well known. In this paper we have discussed well log data issues with core measurements and fluid properties. In general, well log data is always considered very accurate. However, the precision required for quantitative seismic interpretation indicates that if possible, well log data should also be corrected for necessary corrections like poor borehole condition, well trajectory, mud-filtrate invasion and tools problem. Therefore, poor quality log data should be identified and edited using appropriate techniques like empirical relations and rock physics modeling. In this study, rock physics modeling has been used for identification, correction and to generate missing logs of any wells in the Sarawak basin, Malaysia. The main focus of log editing/modeling was on the elastic logs i.e. P-sonic, shear sonic and density. Thin laminated sands and shaly sands impose major challenges for rock physics modeling and log editing. Special emphasis has been given for modeling of thin laminated sands and shaly sands in the study area. Different fluid substitution methods and upscaling techniques have been tested and it has been found that an iterative editing and well seismic calibration is a must for correct rock physics model for laminated and shaly sands in Sarawak basin. The rock physics based well log condition workflow will be elaborated further in the paper. A rigorous quality check including iterations for petrophysical interpretation, depth dependent rock physic model parameters are very crucial to explain the recorded well logs and fluid substituted responses through integration with core measurements and seismic data. It has be established that pre-stack seismic gathers and synthetic CDP gather matching should be analyzed for insitu case before embarking on modeling other fluid responses in the reservoir. The rock physics model has been used to show the impact of well log conditioning for AVO modeling and reliable quantitative interpretation. Based on analysis of several wells in Sarawak Basin, it can be mentioned that data QC and conditioning is very important to understand amplitudes and to boost the confidence especially for thinly laminated sand-shale sequences.
-
-
-
Application of Spectral Decomposition and Inversion to Understand the Structural Development of Thrust Belts
Authors Mirza Naseer Ahmad and Shamim Haider and Ramly B. ManjaSince first discovery of oil on Khaur structure, oil companies have been actively looking for hydrocarbon in the thrust fold belts of Pakistan . A lot of regional work has been done to understand the evolution of thrust fold belts and development of individual structures. Most of the studies were focused on building a regional model based on plate tectonic, satellite imageries, surface geology, gravity, magnetic andseismic data. When it comes to developing detail understanding of individual structures, seismic data has been mostly restricted to making structure maps at reservoir level. In this paper we are demonstrating that special techniques like Spectral Decomposition and Inversion should be used regularly to build detail understanding of the structural and stratigraphic complexities involved within the individual structures. Working backwards this will result in refining our regional structural and stratigraphic model besides enhancing exploration and development capabilities of the area. Spectral Decomposition and Inversion was applied on a structure in Kirthar /Sulaiman foldbelt. The results were encouraging and showed both structural and stratigraphic detail not seen on the conventional seismic.
-
-
-
Rapidly Integrate R&D into the Mainstream Workflow and Bring Software Closer to Operations Through an Open Software Framework
More LessOpen software development is key to providing complete unified subsurface workflows with the best in class technology throughout. Through openness, we can also move software closer to operations and thereby better solve complex reservoir challenges. Schlumberger is committed to providing this innovation and openness through the Ocean software developers’ framework. Schlumberger’s Petrel software provides the canvas, scalability and core functionality taking the geoscientist seamlessly from seismic through to simulation while Ocean offers the opportunity to fill any workflow or reservoir specific gaps for challenging discoveries. With Ocean the R&D department can quickly deploy new solutions directly into the daily workflow, independent software vendors can equally and easily integrate their technology, or if you don’t have the software development skills in your organization, Schlumberger can provide the development for you. The result is a seamless seismic to simulation workflow with best in class technology customized to solve your specific reservoir challenges. Ocean and Petrel are key components to the overall Schlumberger strategy and used by all divisions linking software used at the desktop much closer to operations then has ever been possible in the past.
In this presentation I will discuss how the Ocean framework has been used for internal development to rapidly deliver cutting edge technology, how an independent software provider has used it to provide best in class technology directly inside of Petrel, how we have used this to develop technology to aid operations unified within the Petrel environment, how it has been used to deliver an innovative game changing R&D project that crosses domains, how a major international operator has used it to customize workflows and finally how it can bring new innovation from academia to the industry. Ocean is used in around two hundred plug-ins in commercial SIS software, internal Schlumberger software, universities, oil and gas companies and independent software vendors software projects, and the list is constantly growing.
-
-
-
Increasing the Accuracy of Depth Conversion Using Hybrid Velocity Modelling: Case Study at South East of Malay Basin
The time to depth conversion through the use of analytical functions has been a common procedure in Seismic Interpretation for many decades. This paper describes an innovative methodology for time to depth conversion based on the construction of a debiased velocity grid calibrated with a numbers of velocity functions. This method addresses the advantage of 3D seismic velocity which incorporates geologically feasible lateral and vertical velocity variations and available well information. As such makes it particularly suitable for time to depth conversion in complex structural environment. A series of quality control processing are key the proposed method. This leads to increase in accuracy of the velocity model as well as reduction of cycle time.
-
-
-
Hydrocarbon Exploration in a Tertiary Stratigraphy of the Offshore, Nile Delta Basin, Egypt
Authors Mohamed Ibrahim, Gamal R. Gaafar and Eslam Esmaiel and Ayman HassanThe offshore Nile Delta remains a sparsely explored area of the Mediterranean, Nile Delta considered as a prospective area for hydrocarbon exploration. It is located at the western side offshore Nile Delta. The available geophysical, geologic and well logging data obtained from exploration and development wells were used to establish static and dynamic models of the area to calculate gas in place prior to production. High resolution 3D seismic data and recent exploration activities proved several plays with complex
depositional settings. Tertiary channels systems can be recognized using 3-D seismic and attributes interpretations with tying channel characteristics to well control within a sequence stratigraphic framework to predict the reservoir facies within undrilled exploration areas. The interpretation and mapping of Oligocene, Miocene and Pliocene sequences together with the seismic attribute extractions indicate the presence of several upsides potential developed within the area of study. Oligocene channels complex running in a NW-SE direction. The sequence stratigraphic approach has shown very applicable for mapping the Pre-Messinian depositional systems, Nile Delta and present drilling of these features have confirmed the presence of Pre-Messinian channel complexes as indicated in seismic data, and introduces a new play in the study area. Well logging data proved the presence of reservoir, with good porosity and permeability, ranged from clean sandstone to interbedd nature. The depositional environment and tectonic evolutions of offshore Nile Delta Basin allow the presence of hydrocarbon source rocks with adequate maturity. The hydrocarbon migration path which goes laterally up dip toward the prism of Nile Delta basin The shallow gas discoveries in the Pliocene sands and condensate oil in the Oligocene – Miocene and Mesozoic reservoirs indicate the presence of multiple source rocks and a suitable conditions for hydrocarbon accumulations in both biogenic and thermoginic petroleum system. Leakage of natural gas from traps in the Tertiary rocks resulted in gas chimneys related to the deep seated faults in the Nile delta.
-
-
-
Identification and Modelling of Karst Features in a Carbonate Field, Sarawak Basin Malaysia
Authors Liew Wei Long, Nguyen Huu Nghi and Goh Sing Thu and Rahim MasoudiKarsts are features shaped by the dissolution of a layer or layers of soluble rocks, a process known as karstification which occurs in carbonate rocks during sub-aerial exposure when the relative sea-level is at the lowstand. Karsts features vary in sizes which can range from fracture to cavernous size. The Karsts pose challenges especially to exploration and appraisal drilling where severe mud loses have been observed and such incidents were evident in the field under study in this work. Yet, the influence of the Karsts towards reservoir behaviors is hitherto uncertain during the production stages. The Karsts could be the felon behind production wells cutting water earlier then expected as it can act as high permeability conduit that encourage fast water influx into the
reservoir. This was observed by the unexpected water breakthrough of one of the producing wells after just two years of production. Karsts acting as water conduits are not uncommon, as “fracture-karst water is an important water resource for water supply in North China” (ZHU Xueyu et al) and “the flow velocity of fracture-karst water is much faster than the velocity of porous water on an average.” (ZHU Xueyu et al). Furthermore, the Karsts may contribute to the increase of volumetric of the field by virtue of their pore volumes. Driven by concerns of reservoir performance due to Karsts impact, the challenge is to incorporate Karsts features in the current static model for this field in order to obtain a more accurate representation of the reservoir for later stage dynamic simulation.
-
-
-
The Roles of Coal in Hydrocarbon Exploration in the Malay Basin: The Good, the Bad and the Ugly
Authors Deva Ghosh, Samsudin Jirim and Salbiah Isa and Peter AbolinsThe multifaceted role of coal in hydrocarbon exploration is analysed from a Geology and Geophysical perspective. The Malay Basin is one of a number of extensional ‘rift’ basins on the Sunda shelf of SE Asia. These basins generally have two distinct phases; (a) syn rift and (b) post rift. Tectono-stratigraphic basin development coupled with depositional environment has a direct relation with the charge system and hydrocarbon habitat of the basin. Miocene fluviodeltaic shales and coals occur in the Malay basin in the post rift section and are stratigraphically widespread from Group E to I and are a volumetrically significant facies.
-
-
-
Over-Under Deghosting
More LessFor streamer acquisition, the reflection of the up-going wave field at the sea surface (or ghost) contaminates the recordings, and in particular, significantly attenuates the lower frequencies. In order to eliminate the ghost, we may choose to advocate the recording of the wave field at several different depths: the so-called ‘Over-Under’ technique. In this paper we demonstrate on real example the value of this technique as well as some theoretical insights.
-
-
-
A Systematic Seismic Approach Toward a Major Gas Discovery of “Subtle” Structural Trap in North Malay Basin
Authors Ji Ping and Zuliyana Ibrarim and Norhafizah MohdExploration since 1960s has made Malay Basin be a matured petroleum province. Most of the large structural traps have already been drilled by PSC contractors. Booking reserves in Malay Basin has been becoming more and more challenging in recent years. The paper will present a recent success application of seismic technology in the big gas discovery by Petronas. It encourages explorationists to apply the comprehensive technology for prospect generation in the remained large potential of Malay Basin.
X structural trap was revealed in FY 08/09 prospects scanning. It is a “subtle” or “hidden” trap because it can’t be detected on seismic sections or Two-Way-Time maps. But further seismic attributes analysis suggested that there are “slant spots”, class II/III AVO, phase change, low frequency, and amplitude shut off with possible structural trap contours. All above phenomenon is proven with gas bearing by nearby fields. 3D PSTM seismic RMS velocity is used to build a comprehensive velocity model. A large structural trap emerges in the depth maps from D to Lower E groups. “Slant spots” become “flat spots”. Seismic amplitude and isopaches with geology study also suggest that the reservoirs are better developed than those in the nearby field. X-1 well successfully tests the potential of the prospect. The total net gas pay from D to E group is over 150 meters. DST tests tell that CO2 content is only 4-9% in Lower E section. Post drill review further reveals that the seismic pull down section is because of the shallow gas cloud and thick gas reservoir column. The significance of the big discovery is as following: 1) Right approach of current technology still can find big field in the matured Malay Basin. 2) There are opportunities to look for big structural prospect in the “subtle” trap area of Malay Basin.
-
-
-
North West Borneo Deepwater Fold and Thrust Belt: What Controls the Hydrocarbon Column Height?
Authors William Ngu, Tomas Van Hoek, William Wilks and Peter Shiner and Charlie LeeThe deepwater acreage in the active fold and thrust belt of North West Borneo hosts a number of world class hydrocarbon accumulation. One of the critical success factors for exploration in the fold belt play is understanding the key controls on hydrocarbon column height. In the past, mechanical top seal capacity, or 4-way dip closure were seen as the main controls on hydrocarbon column height. This was revisited during the 1st phase of Deepwater Traps and Seals study carried out between 2007 and 2008. This study found evidences that fault-dependent columns are present and a number of structures are not fill-to-spill (geometrically), thus challenging 4-way dip closure as the dominant control. Moreover the study also found that at present day many traps in NWB deepwater still have significant mechanical top seal trap margin at the crest of structure. This required a change of paradigm which led to a 2nd phase of the study to examine the capillary seal capacity. A workflow was derived to investigate the relationship of the capillary seal capacity with depth. The result shows that the buoyancy pressures arising from observed hydrocarbon columns can be modeled by two capillary seal trends: (1) a silty-shale trend and (2) a shale trend, with most of the data clustering around
the first trend. This observation suggests that the dominant control on hydrocarbon column height in NWB deepwater is capillary seal capacity, which is in contrast with many other basins in the world. This can be explained by the more silty nature of the top seal, which is supported by core data. An intriguing correlation is also found between capillary seal capacity and seal depositional environment as indicated by the interpreted Depositional System Element (DSE). Capillary seal capacity decreases from drape DSE to slope wedge DSE to fan fringe DSE. Consequently, interpretation of top seal DSE based on seismic facies can be used to determine capillary seal capacity, and used as an input into hydrocarbon column height prediction ranges. In addition, this revised understanding has a significant impact on the NWB deepwater portfolio due to the increased Possibility of Success (POS) associated to fault dependent closures with hydrocarbon column height within the estimated silty-shale capillary seal capacity.
Deepwater Traps and Seals study is currently still an ongoing effort, with plans to carry out more mercury injection tests and X-Ray Diffraction aimed at constraining the capillary seal capacity better, as well as additional fault seal analysis.
-
-
-
Deep Pore Pressure Prediction in Challenging Areas, Malay Basin, SE Asia
More LessAccurate pore pressure prediction is not trivial anywhere, but becomes especially challenging in HPHT environments, where many geological processes commence and make rock properties inherently less predictable. In such an environment the traditional methods to estimate pore pressures ahead of the bit must be modified, and in some cases replaced. Heavy reliance on seismic-derived pore pressures is HP/HT environments is likely to lead to unacceptable uncertainties, and should be replaced by models based on geological processes. The traditional approach to pore pressure predictions, which works well in young, rapidly deposited and low temperature sediments, such as occur in Tertiary Deltas (e.g. Gulf of Mexico, Nile Delta), is based on principles which govern compaction of compressible sediments such as shales. During burial, as compaction proceeds, porosity is reduced in the sediment, driven by stress. If sediments are not sufficiently permeable to allow complete dewatering within the time frame that a stress is imposed (for example during and after addition of load during sedimentation) the increment of additional stress is distributed only partially on the grains and the remainder on the fluids. Incomplete dewatering leads to the overpressure mechanism termed compaction disequilibrium where the magnitude of overpressure is controlled by the weight of the added load (vertical stress), as well as rock properties such as compressibility and permeability. Typically, pore pressure profiles evolve with depth to be overburdenparallel. Current pore pressure prediction capability is well optimised for these where compaction disequilibrium is the primary source of overpressure. However, as industry drills deep targets where temperatures typically exceed 100-120oC (~250oF) and often much higher, the ability for conventional porosity-based pore pressure prediction methods to deliver satisfactory results diminishes. Above this threshold temperature pore pressures are likely to be underestimated, as techniques using interval velocities, wireline or Logging While Drilling data such as sonic and resistivity become increasingly unreliable. In these higher temperature conditions, additional pore pressure can also be generated by fluid expansion mechanisms (aquathermal pressuring, hydrocarbon maturation, inter-granular water released during clay diagenesis) and framework weakening/load transfer (the modification of the load-bearing part of the sediment such that the rock becomes weaker/more compressible, for example when smectite re-crystallises as illite or when kerogen transforms to oil/gas and residual kerogen). Fluid expansion and framework weakening causes the pore pressure to increase at a rate faster than rate of increase of overburden stress. Overpressures generated by compaction disequilibrium and fluid expansion methods have been quantified by Swarbrick et al. (2002). Load transfer/framework weakening has been quantified by in Lahann et al. (2001) using data from the Gulf of Mexico. Our recent work in the High Pressure/High Temperature region of Mid-Norway estimates a contribution to pore pressures of approximately 17 MPa (2500 psi) overpressure at depths of 4500m (15,000 feet) through the mechanism of framework weakening. In HP/HT environments, therefore, very significant contributions of secondary overpressure (in addition to that from compaction disequilibrium) can be expected as temperatures well in excess of 100-120oC are encountered. If not anticipated prior to drilling, this additional overpressure leads to major drilling surprises with implications for health and safety (as well as geological implications such as hydraulic failure of top-seals in reservoirs and re-migration of hydrocarbons). Steps towards an improved understanding of these processes and their
contribution to overall sediment overpressure would provide a significant contribution to pore pressure prediction modelling in deep and hot environments. Therefore, this paper is designed to bring together some new research results from studies of overpressure in the Malay Basin as well as Gulf of Mexico, SE Asia and Northern Europe to develop a workflow and methodology to characterize and quantify pore pressure in deep targets and inform the next generation of pore pressure prediction capability in HP/HT environments.
-
-
-
Fitting Sumandak Stratigraphy into Sabah Regional Chronostratigraphic Framework
More LessSumandak cluster fields is located in the Samarang Asam Paya PSC within Sub-Block 6s – 12/ 18 of Block SB310 (Figure 1) and operated by Petronas Carigali Sdn. Bhd. The success story begins with the discovery of Sumandak Main by Sumandak-1 well drilled in September 2001. Seven more exploration wells were drilled on the same play in the area between 2001 until 2003, which resulted to the discoveries of Sumandak Tepi and Sumandak Tengah. To date, twenty-eight (28) development wells have been drilled on Sumandak area and the fields are currently on production. In order to further explore the hydrocarbon potential of this area, a regional study with sequence stratigraphic approach was carried out in 2008. The main objective of this study is to generate stratigraphic framework of Sumandak that can be correlated to the Sabah regional chronostratigraphic framework (figure 2). The generated stratigraphic framework will help to facilitate interpretation in the Block SB310 and surrounding areas. In addition, the study was also aimed to identify any upside hydrocarbon potential for further exploration. The approach adopted in this study was based on Exxon’s techniques (Van Wagoner et. al. 1990) which defined Sequence Boundary (SB) as a product of relative falls in
sea level. Seismic data and well data (logs, cores & biostratigraphic data were used to identify major bounding surfaces in order to establish a framework in which genetically related facies can be studied and a realistic depositional model can be constructed. Sequence stratigraphic interpretation such as identification of sequence boundaries, maximum flooding surfaces, reflector terminations (onlap, downlap, toplap and truncation) were done on hardcopy of several selected key seismic lines prior to extend the interpretation to the rest of the available seismic data. The tectonic setting and basin evolution of the Sabah Basin is very much related to the closing of the proto-South China Sea/ Rajang Sea. The opening of the South China Sea since Oligocene causing
microcontinents of Dangerous Grounds and Reed Bank to drift and collide with Sabah margin. Active tectonic plate movements throughout Eocene and Miocene have resulted in the development of different provinces across Sabah Basin hence creating the Inboard Belt and East Baram Delta where the study area is located. Sumandak Field is located within a series of progradational deltaic system where rapid sedimentation was observed forming the topset, foreset and bottomset facies. In each successive deltaic system, the basin depocenter moved further offshore to the northwest. The study has recognized fifteen sequence boundaries in Sumandak area of which eight are the existing SBs based on previous interpretations and another seven are new SBs introduced in this study (Table 1 & Figure 3). All identified sequences are categorized as the 3rd order sequence and regionally correlatable with Kinabalu, Trusmadi, Glayzer and Labuan-Paisley Syncline areas. This paper shall discuss the result of the study, which is the refinement of previous interpretation on sequence boundaries in this area. Using various data for integration, the study has established a new stratigraphic framework for Sumandak and the correlation of Sumandak sequence stratigraphy with the Sabah Regional Chronostratigraphic Framework. The upside potential for further exploration in this area shall also be highlighted and discussed.
-
-
-
Updating Reservoir Models; Auditing, Updating and Rebuilding
More LessAs time passes our understanding of a reservoir changes, more information becomes available. Our original ideas about the geology, the fault compartments and the ultimate recoverable volume of oil or gas are modified by the acquisition of additional information about the reservoir. Our expectation is that as we collect more data, our uncertainty about the reservoir is reduced. As we know more about the reservoir our expectation is that our predictions for the recoverable hydrocarbons will become more accurate. This paper considers the dilemma of deciding how to incorporate new information into the model. Most of the time, it appears that there is no consistency or clarity in the strategy. More worryingly, it appears that not all data is considered equally.
-
-
-
True Amplitude Seismic Imaging Beneath Gas Cloud Using Full Waveform Transmission Deconvolution
Authors Ahmad Riza Ghazali and D.J. Verschuur and Dries GisolfConventional imaging processes for a situation with a gas cloud do not offer satisfactory solutions. Due to the complex wave propagation through the anomaly and the transmission imprint on the reflections from below these complexities, the image below the anomaly is usually not properly recovered. We aim at constructing full waveform transmission operators (including the codas) from the gas cloud reflection response via an effective medium representation. True amplitude imaging is achieved via multi-dimensional deconvolution for these full waveform transmission operators. The feasibility of 1.5D non-linear full waveform inversion using a genetic algorithm (GA) and 2D transmission deconvolution has been successfully demonstrated (Ghazali et al., 2009a; Ghazali et al., 2009b; Ghazali et al., 2009c). The results are encouraging enough for an extension of the inversion process to the full 2D case, and eventually to 3D. However, extending this approach to a multi-dimensional non-linear full waveform inversion is not simple or straightforward. In this paper, we present a feasibility study on 2D synthetic data, for which the operators are obtained by forward modeling through the gas cloud region. For the 1.5D case, it is demonstrated that a targetoriented full waveform inversion process to obtain effective gas cloud for medium parameters is viable.
-
-
-
Contrasting Dolomite Textures of Miocene Carbonate Platforms in Central Luconia, Sarawak, Malaysia
Authors A. Rulliyansyah and Bernard J. PiersonDolomite is common in the Miocene carbonate platforms of Central Luconia, Sarawak but so far few studies have addressed the dolomitization processes in these isolated platforms. This paper presents the results of an investigation of dolomite horizons and the origin of the dolomite in two Miocene platforms of Central Luconia. 65 thin sections and core plugs were selected from two carbonate platforms, located in the southern and northern part of the province. Polarized light and cathodoluminescence petrographic analyses, SEM investigations, stable isotope and elemental composition analyses were carried out to reconstruct the succession of diagenetic events. Two distinct dolomite textures characterize the two platforms, namely mimetic replacement fabricpreserving) in the northern platform, and fabric-destroying with sucrosic dolomite texture in the southern platform. Dolomite crystal size ranges from < 10 μm to 100 μm in both cases. There are also indications of overdolomitization, mainly in pore-lining and pore-filling dolomite cement. In cathodo-luminescence, all dolomites are generally dull-red to extinct, although a few samples from the northern platform show occurrences of bright luminescence in the outer dolomitic cement rim. Both platforms have undergone diagenesis associated with the mixing zone. Dolomoldic porosity and geopetal structures suggestive of subaerial exposure and karstification, are mostly developed in the northern platform, whereas intercrystalline porosity occurs together with dolomoldic porosity in the southern platform. Dolomite seems to form as an early replacive phase. Late sparry calcite occurs in the northern platform and poikilitic calcite in the southern platform, suggesting (shallow?) burial diagenesis. Other types of cement indicative of early marine diagenesis, freshwater phreatic to burial diagenetic realm are also present (e.g.: dog tooth cement, isopachous cement, micritic cement, syntaxial overgrowth and drusy calcite spar). Stable isotope compositions suggest that the dolomite could have formed from slightly depleted seawater or fluids that have been diluted by meteoric water in both platforms. The δ18O values in the northern platform average -3.06 ‰ (V-PDB) compared to -2.71‰ in the southern platform. Calcite cement in both
platforms are more depleted in δ18O (-7.12 ‰ in the north and -6.37 ‰ in the south), probably due to a high intensity of meteoric water penetration in a late stage of cementation during a period of subaerial exposure. δ13C values of dolomite showed very little influence of carbon derived from soils during exposure.
-
-
-
Fractured Basement Characterization from Multi-Attributes Guided Integrated Continuous Fracture Modeling and Discrete Fracture Network Modeling
Authors M. Lefranc and A. Carrillat and A. CarnegieThis paper demonstrates an integrated approach to model conditioning for fractured basement reservoirs through application of Continuous Fracture Modeling (CFM) and Discrete Fracture Network modeling (DFN). The approach has been implemented into an advanced software system, and is built on four main steps: 1) the interpretation and analysis of high resolution borehole images, sonic data (Stoneley and shear), log and core data which provide high vertical resolution information for a limited number of locations, and 2) the prediction of the fracture intensity in the inter-well space, 3) the generation of the DFN model, and 4) the DFN upscaling. The process involves identifying the flow contributing fractures using a detailed analysis of borehole images data and then combining them with Sonic measurement and production data. An optimized set of key seismic attributes is used to constrain the propagation of fracture intensity away from the wells: ‘fracture sensitive’ attributes such as frequency attenuation and results of full stack inversion, and texture seismic attributes derived from poststack signal processing. Fracture models are then contructed using first neural network artificial intelligence method, and secondly discrete fracture network. The robustess of the method is based on both qualitative and quantitative analysis of the data at each step of the workflow.
-
-
-
Spatial Variability in the Belait Formation: Impact on Reservoir Characterization and Management Considerations
More LessSedimentary facies in the Belait Formation in North-eastern Sarawak show tremendous spatial and temporal variability. This variability needs to be evaluated to increase our understanding and management of reservoirs and thereby assist in enhanced oil recovery endeavors. The heterolithic facies in the North shows varying proportions of sand to clay. The main variations in sandstones in this area include laterally continuous or discontinuous mud-drapes, with varying degrees of thickness, lengths and density per square metre (mud drape facies), close spacing in migrating channels with fills of sand with high carbon contents at high geomorphic positions, presence of remnants of conglomerates (oligomict), and the occurrence of dark gray massive shale facies and massive sandstone facies in top stratigraphic positions. The central section along the North-South ridge comprises has a similar geology in addition to the occurrence of massive sandstone facies and dark gray massive shale facies. Paleocurrent analysis shows that these fluvial sediments were part of a deltaic system with flow directions between 40o and 180o. Temporal analysis indicates that magnitude of the current was fairly consistent. A conglomerate (oligomict) facies overlies the Setap Shale Formation in the South. Variations in fabric are abundant. Thermal conductivity studies suggest that the behavior of these reservoir quality rocks is strongly dependent on fabric. The variability created by the heterogeneity in the Belait Formation has the potential to impact enhanced oil recovery considerations and the efficiency of respective units in the Formation to function as seals or as reservoirs.
-
-
-
In the Quest of Open Fractures in the Crystalline Basement of the Malay and Penyu Basins
Coherent rock may fracture naturally into four predictable orientations/attitudes with respect to the generating stress system. Thus formed, fractures parallel and perpendicular to the maximum principal stress are potentially open features. Area and region-wise, this maximum stress direction is commonly horizontal (SHmax). Slip on the two shear fractures may further generate second-order fractures, with similarly predictable orientations/attitudes. Fractures are the major contributors of secondary porosity in crystalline rocks. The crystalline basement of the Malay and Penyu basins consists of metamorphic rocks as well as occasional pre-Tertiary igneous bodies. These rock types are analogous to those outcropping in the Eastern Belt of the Peninsula. Extensive field studies throughout many years have established that these rocks were subjected to two (for the lower Mesozoic) and up to four multiple (Carboniferous) tectonic deformations. Each of the deformations may have resulted from differently orientated stress systems and consequently their respective fracture characters may have become degraded or destroyed. At regional scale, radar satellite imagery and aerial photographs show preferred fracture orientations that are consistent with pre-Tertiary stress systems. For instance, initially open fracture directions in lower Mesozoic-upper Palaeozoic basement correspond with Cretaceous dolerite dykes. The responsible SHmax direction was ENE-WSW for this particular case. Regional fractures (most probably all are faults because of their several-kilometre-long dimensions) in the Malay and Penyu basins also show preferred orientations that are consistent with those mapped onshore (figure 1). Outcropping “crystalline basement” rocks in the Eastern Belt display a variety of fracture orientation as well as fracture character. Differences with those implied by the regional lineament patterns could often be determined as being of local nature, such as being situated within a shear zone, being associated with the intrusive form of an igneous body, or resulting from decreasing overburden, and so forth. Nevertheless, some useful relationships between lithology, rock texture, and fracture density were established (figure 2). Tertiary SHmax orientations in the Malay and Penyu basins were initially determined using caliper logs. This was strongly supported by subsequent well-bore breakout studies using images, such as FMI. Most of the Malay Basin is governed by N-S SHmax (figure 3). A belt following the Western Hinge Line on the western side of the Malay Basin has SHmax that ranges between Northwest and West-Northwest . The Penyu Basin is under the influence of SHmax orientated East-West (figure 4). The regional fault pattern in these basins have preferred orientations consistent with the SHmax orientations (compare with figure 1). Finally, we suggest that open fracture directions in the basement of the Malay and Penyu basins are both parallel and perpendicular to the SHmax directions as indicated for the respective areas in figure 4. These
fracture directions provide fluid pathways; in addition the proximal fracture environments of the basement are most likely more favourably charged by fluids compared with those remote from the structures.
-
-
-
Delineation of Stratigraphic Prospect from the Integrated Analysis of Geological Model, Well and 3D Seismic Attributes – a Case History from Temana Field, Sarawak, Malaysia
More LessThe Temana field is located 30 km offshore Bintulu in Sarawak basin at water depth of 96 ft. The field was discovered in December 1962 and so far 22 exploratory and appraisal wells have been drilled. The field is in its production since November 1979 and till January,2009 it has produced 128.32 MMstb of oil from H,I ,J &K reservoirs of Early to Middle Miocene age of which major production ( almost 90%) comes from H & I reservoirs. The Temana structure comprises of an elongate, east-west trending, west plunging, heavily cross – faulted upthrusted anticline. The structure is situated at the fringe of the Balingian basin, a major tectonic depression offshore Bintulu and is bounded to the north and south by major reverse fault zones. The anticline is dissected by NNE-SSW trending faults. The Temana structure is traditionally subdivided into three areas: Temana West, Temana Central and Temana east (as shown in the Figure 1). The entire I sequence consists of a number of fining as well as coarsening megasequences reflecting different pulses of coastline progradation and / or lateral shift interrupted by phases of minor marine transgressions. The inferred depositional model in I sequence consists of progradation of the shoreline with deposition of coastal and nearshore sands followed by a minor sea level rise causing shoreline to retreat or stabilization. Thereafter the shore line progrades again because of excess sediment supply and the coastal plain aggrades. At the end of progradational episode formation of peat and coal swamps take place on the coastal plain. Thereafter a renewed rapid shoreline progradation caused by excess sediment supply. I-65 reservoir is one of the main producers among other reservoirs in Temana, especially in the saddle. The paleodepositional environment for I-65 is interpreted as low energy regime distributary channel within lower coastal plain with the paleo current direction towards NE – NNE from SW (as shown in the Figure 2). A study has been carried out integrating the conceptual geological model with the seismic attributes and the production data from the nearby wells to identify unexplored channel arm within the developed area on I-65 and I-60 reservoirs. The workflow involves well to seismic correlation, extraction of seismic amplitude within the reservoir window, validation of the seismic amplitude with the drilled wells, integration of the seismic attribute findings with the geological model leading to the delineation of untapped prospects. I- 60 and I-65 have been re-interpreted (Figure 3) and flattened on I-60 level to show the channel like geometry (Figure 4). Attribute like RMS amplitude have been extracted within the reservoir window. The amplitude extraction have been carried out for I-60 reservoir window at 14 ms, 16 ms and 20 ms of which 16 ms represents the most likely scenario (Figure 5 ). Similarly, the RMS amplitude have also been extracted for I- 65 reservoir at 12 ms, 16 ms and 24 ms of witch 16 ms represent the most likely case (Figure 6 ). The attribute maps show about 80% correlation with the well findings (as shown in the Figure 7). The identified prospects are dominantly of stratigraphic play. The log correlation (as shown in the Figure 8) depicts the discontinuous nature of the sands which is also evident from the attribute study. The stratigraphic trap controlled geological model successfully explained the sand body and fluid distribution at nearby wells which was difficult to explain with structural play concept. The delineated sand body gives an indication of channel configuration both at I-60 and I-65 level which correspond to the conceptual geological model. Figure 9 represent super imposition of I-60 and I-65 channel configurations indicating similar orientation. This paper describes the work flow and the findings of the study which resulted in identification of new resources within the Temana Field in I-65 and in I-60 reservoirs. The integrated study has resulted in improved geological model and understanding of prospects within Temana field. Once successfully appraised, this would open up avenues for delineation of similar prospects and reserves accretion within the Temana field.
-
-
-
Occurrence of Hydrodynamic Play in Malaysia
Hydrodynamic play is known to occur in onshore basins where the elevation differences result in hydrodynamic conditions which trap huge pools of gas in basin centers. Pressure plots indicate that the gas line is below the water line as opposed to the normal condition where the gas line is above the water line. Hydrodynamic play is also likely to occur in our sedimentary basin where a sharp change in water depths can also initiate hydrodynamic conditions causing titled water contacts. Even though this hydrodynamic play exists in our basin, it was not really recognized as such. Discoveries with tilted water contacts in our own sedimentary basin will be highlighted in this paper. The tilted contacts of these hydrocarbon discoveries were simply dismissed by the operators concerned with flimsy explanation of depth and pressure measurements errors and multiple, discreet water contacts. Even specialized processing work has been carried out extensively trying very hard to flatten the tilted contact! One such example is shown in Fig. 1 with obvious titled water contact and a single gas leg and two water legs. The potential in this new play concept will also be discussed in this paper. The hydrodynamic phenomenon causes water to lie above oil and gas in either structural or stratigraphic traps. Wells drilled in the past at the crest of the structural traps may lead to the wrong dry hole conclusion. Hence, it is possible that the hydrocarbon potential downdip was not fully assessed (Fig. 2). There are also other prospects with tilted
contacts which have not been tested and some of these prospects will be shown in this paper.
-
-
-
Successful Application of Real-Time Pore Pressure and Fracture Gradient Modeling in Deepwater Exploration Wells
More LessThe accurate modeling of pre-drill, while-drilling and post-drill pore pressure and fracture gradients (PPFG) for an exploration well is a very challenging process, particularly in deep water applications. Erroneous PPFG predictions and estimations can be a source for unexpected non-productive time in drilling operations due to wellbore integrity or pore pressure related problems resulting in significant cost overruns for the well. In addition to preventing geopressure related problems while drilling, other benefits of real-time
PPFG modeling include identification of formation breathing, better hole cleaning, higher rates of penetration and prevention of differential sticking. This paper presents two case histories of successful PPFG modeling for deep water exploration wells in North Africa and Southeast Asia. The pre-drill PPFG models were prepared using sparse offset well data. In the drilling phases, the models were updated and calibrated based on mud weight, caving shape and leak-off test information. Eaton’s resistivity PPFG method was used to estimate the PPFG model in real-time. In addition to Eaton’s resistivity method, Matthews’ and Kelly’s method was also used in predicting the fracture gradient. A hydraulics model was run in parallel to the drilling operation, so that real-time ECD (equivalent circulating density) could be compared against theoretical values to detect anomalies and to ensure that the annulus pressure stayed within the predicted PPFG window. At the end of the drilling phase, the real-time PPFG model was found to be within 0.1 ppg of actual formation testing pressure readings. Based on the two case histories, the paper will illustrate in detail the process steps required for realtime PPFG modeling and demonstrate the benefits of taking the proper actions to mitigate risks identified by the PPFG model.
-
-
-
Fractured Basement Exploration Case Study in Malay Basin
More LessOil and gas exploration in Malay Basin started by ESSO and CONOCO in early 1970’s targeting on the clastic play. CONOCO focused the exploration for clastic play over southern Malay Basin Concession area. Many discoveries were made after drilling several exploration wells. In Anding, the discovery wells tested oil in clastic Group K and L reservoir sands and the wells were TD’ed in the basement. In 1978, CONOCO relinquished it acreage and the exploration effort continued by PETRONAS Carigali Sdn Bhd (PCSB) with oil and gas discoveries were made in clastic play. By 2004, with the initiative of Southern Malay Basin Exploration Team, PCSB drilled a new structure to the north of Anding field and discovered oil. The new oil discovery was the first fractured basement discovery in Malaysian Basin (Figure 1). A total of six (6) exploration/appraisal wells were drilled with the main objective is fractured basement in Anding area. Based on the well results, the optimum well trajectory was established for exploring in fractured basement play over southern Malay Basin (Figure 2). Surface outcrop study also was carried out at Redang island and surrounding areas (ca. 200km NW of Anding) to firm up the fractures trend and surface analogue for exploration drilling in fractured basement. A consistent shear fractures trends demonstrated by FMI data from Anding wells was observed on the surface outcrops. The existing of surface fractured basement at Redang Island is a good analogue for indepth studies of fracture distribution and its connectivity within basement reservoir. With the comprehensive study on the fracture distribution and connectivity within fractured basement play, optimum well trajectory to be planned in future for exploration and production management of the hydrocarbon resource in Malay Basin (Figure 3). Based on existing wells drilled into the basement in Anding area, new hydrocarbon trap model was introduced. The hydrocarbon accumulation potentially trap in clastic sandstone overlying the basement and in fractured basement as a single fluid system to be existed in Anding field. Integrated fracture study for Anding basement is recommended in order to have a comprehensive and integrated analysis of the distribution and effectiveness of fractures in Anding field prior to early monetization of hydrocarbon resources in Group L and fractured basement reservoirs.
-
-
-
Continued Success in a High Subsurface Risk Environment; The Cendor Story
Authors C.Y. McCants, Hanif Hashim, Gary Leaf and Wan Nawawi and Natasya PawantehMarginal field developments are always challenging but they can be done commercially and in reasonable time frames if an innovative development approach and effective risk reduction efforts are applied to control costs and manage risks. An example is the Cendor field which is located offshore Peninsular Malaysia, in block PM-304 along the eastern part of what is known as the “Jambu-Liang Anticline.” Cendor began production in 2005 with the placement of seven development wells utilizing a Mobile Offshore Production Unit (MOPU). Since that time, more than 15MM barrels have been produced averaging between 14,000-15,000 BOPD from upper H Group reservoirs. Seismic and geological interpretations have divided the Jambu-Liang structure into six fault
blocks; 1) Cendor, 2) Cendor Graben, 3) East Desaru, 4) West Desaru, and 5) Irama. The structure trends eastwest and each fault block is defined by predominantly north south trending faults that probably formed in response to the structural growth of Jambu-Liang that initiated in post-H group time. In 2008-09, the PM-304 partners continued the development approach mindset by performing a successful five well near-field appraisal campaign in East Desaru, West Desaru and Irama. Each well encountered hydrocarbons in the upper H group and identified two gas/oil contacts in East and West Desaru indicating that the faults are sealing (at least in the upper H group) and compartmentalization exists. The current in-house seismic has played a strategic role in identifying drilling opportunities, particularly in the H-15 sands, in each of the fault blocks but limitations do exist due to the resolving power of the sands and the presence of shallow gas that has negatively impacted the signal/noise, to varying degrees, over 75% of the interpretation area. Angle offset data and simultaneous inversion volumes have identified “sand fairways” over the Jambu-Liang structure which have led the partnership to consider three possible depositional settings; 1) A lower delta plain with channels and crevasse splays, 2) A channel belt with “sweet spot” channel sands and an associated sandy flood plain, and 3) Younger channels eroding into an older sandy system. In 2010, the partnership hopes to continue evaluating PM-304 with emphasis on innovation, riskreduction, and cost control.
-
-
-
The Penyu Basin Revisited: The Abandoned ‘Mate’ of The Malay-Natuna Basin
Authors P. Restrepo-Pace, S. King, R. Jones, C. Goulder and Y. Ah Chim and C. RussellThe Penyu basin is a transtensional-transpressional basin that developed approximately coeval to the greater Malay Basin to the north. In spite of the stratigraphic and structural similarities of these basins, Penyu basin has had marginal results in terms of discovered volumes of hydrocarbons, and no commercial discoveries yet made on the Malaysian side of the basin. Conventional industry wisdom has attributed this largely to source rock leanness, most likely consisting of lacustrine-type sediments as isolated pods in the deeper portions of half grabens. Poor drilling results since the early 70’s and the elusive nature of this uncalibrated source rock has kept explorers out of Penyu in recent years. Nevertheless, straddling the Malay- Penyu basin is the largest field discovered thus far: the ~350-400 mmbo Belida field. Belida is distinctive in many ways: it consists of a mildly inverted structure sitting on a basement ridge that separates Malay from Penyu basin, it is not underpinned by source rock, thus relying on long distance migration, and has a distinctive oil signature that can be linked to a possibly significant contribution from a Penyu source. In addition, the Rhu oil discovery indicates that there is a working petroleum system within Penyu itself. Post drill analysis, 3D maturation-migration modeling and detailed structural geology suggests that drilling failure in the Penyu basin may be attributable primarily to the following reasons: structural timing versus peak HC generation, trap preservation (especially on the Indonesian side of the basin), trap definition -not one single well has been drilled using 3D data- and migration- given the likely anisotropic character of the carrier beds. Therefore, even though Penyu Basin has a seemingly less abundant petroleum system than the Malay basin, we sense that of all the perceived risks outlined above, only source rock presence and quality may not be derisked ahead of the drill bit. From our regional studies, there are a multiplicity of plays to be tested independently; and the use of 3D seismic as a key exploration tool is required to test once and for all the prospectivity of the Penyu basin.
-
-
-
Time-Depth Conversion Challenges in the Overpressure Environment, a Case Study from Caspian Sea.
Authors Alex Tarang and Yesphal Singh and Yekaterina LevshinaTurkmenistan’s Block 1 and AB is an asymmetrical ESE-WNW trending anticlinal gas field with small oil rim accumulation and it is located in the South Caspian basin. More than 20 exploration and development wells have been drilled to appraise and develop the main RS8 reservoir of Lower Pliocene age. Two 3D seismic vintages (1997 and 2003) have been PSDM processed and merged to create a single volume. Full suite of wireline logs, with check-shot and VSP have also been acquired in most of the wells in the study area. The formation interval velocity is affected by among other factors – porosity, mineral composition, pore fluid and also effective stress. In overpressure areas, where the sediment are undercompacted, high pore pressure caused the effective stress to be lower which in turn causes the formation velocity to decrease. The normal velocity-depth trend expresses the increase of velocity as porosity is reduced during normal compaction, where pore pressure is hydrostatic and the burial depth of the rock is not reduced. Lower than normal velocity anomalies have been observed in the overpressured wells. On the other hand, in the northeastern most portion of the block where significant uplifts have taken place, loss of porosity due to earlier compaction process are not restored. Therefore, porosity reduction due to earlier compaction processes express itself in higher than normal interval velocity. Several different methods of depth conversion utilizing well and seismic velocity or both has been tested and compared. Seismic to well tie for major formation tops and corresponding horizons has been carried out for all the well penetrations in order to have optimal average velocity at well locations. The velocity trends were also constrained by knowledge about the velocity of the rock at the mudline and at infinite depth. The results shown that Vo-K approach plus high density picked seismic velocity calibrated to well velocity and constrained by other geological information such as the formation isopachs and isochrons give the best result.
-
-
-
Construction of Static Model for Structural Complex Area in Deep Water Environment
More LessExploring and producing deepwater reservoirs pose significant challenges to companies due to the high exploration, development and production costs. Great uncertainties and risk exist in the evaluation of deep water reservoir because of the environment, sparse well control, and lack of direct measurement of reservoir properties. Proper modeling of deepwater reservoir provides companies with tools to evaluate these reservoirs and quantify the risks associated with their development. This paper will describe an applicable approach in developing detailed geological models constrained by 3D seismic data in a complex and faulted turbidities field. This approach was developed in X field which has a complex structure deposited in deepwater environment. The study area is located in deepwater area with water depth of around 800 meters. The faulted structure of this field is often associated with classical λ faults a nd Y faults, provides serious restrictions when building the framework model. Construction of a realistic 3D facies m odel in heterogeneous reservoir is affected by significant uncertainties when based only well information. Integration of additional constraints such as 3D seismic data and sedimentary concept can significantly improve the accuracy of reservoir model. The objective of the proposed approach was: 1. to construct an accurate framework model for complex and faulted field. 2. to integrate both geological and seismic information in a coherent fine-grid model. 3. to account for uncertainties in heterogeneity distribution.
-
-
-
Quantitative Integration of Geology and Geophysics for Reservoir Modelling: A Case Study
More LessGeology, rock physics and geophysics are combined quantitatively in a geostatistical inversion to produce reservoir models of a tidally influenced shoreline to deltaic environment. The geological input is in the nature of structural elements, stratigraphic elements, depositional environment and prior facies probability volumes. The rock physics is introduced through depth trends, stratigraphic trends and relationships between the petrophysical and elastic rock properties. The geostatistical inversion combines this quantitative information with angle dependent seismic and well log data to produce models that are consistent with all a priori knowledge. The impact of the geological facies probability volumes versus the seismic influence on the results can be estimated by comparing models with those produced using probabilities alone and with those using seismic inversion alone. The geological facies probability volumes ensure that the resultant models are consistent with the depositional environment and the seismic data constrain the lateral variations in facies and property distribution. This modelling is applied to a case study from Vietnam where the results are used to mitigate risk in field development.
-
-
-
Closing-the-Loop Between Reservoir Models and Seismic Gains Through the Pains
Starting in 2007, Sarawak Shell has made a concerted effort to include 3D Close-the-Loop (3D CtL) into our reservoir modeling workflow. The idea behind 3D CtL is to compare the static and dynamic model, in time, to the seismic interpretation and seismic data to ensure consistency. At the foundation of this workflow is an understanding of the rock and fluid properties required to transform reservoir properties into acoustic properties, which are used to convert the depth model to time and generate its seismic response. We have sought to make 3D CtL an integral part of the modeling workflow – resulting in robust models that are consistent with all subsurface data, including the seismic. The expectation is that 3D CtL would be applied iteratively while building the static model (framework and properties) in order to correct obvious mismatches between model and seismic. We have gained experience applying 3D CtL for both carbonate and clastic fields. These gains have not been without pains along the way. One of the challenges has been the acceptance of 3D CtL. Some see it as “extra work” that slows down the project and makes it more difficult to meet project milestones under the continual pressure to do things faster and faster. Those who recognized the value have accepted CtL readily, quickly becoming self-sufficient in its application. Currently, most new static model builds are planning for CtL in the work, as including it early prevents more rework later when a model is near completion. An early hurdle to surmount was defining a methodology to quickly “digest” the visual comparison of the synthetic and seismic volumes to determine meaningful updates to the static model. What should one be looking for? Most of our static models have stacked reservoirs or a thick reservoir interval, which encompass many seismic loops. It is very easy to get lost in the details. First it is important to determine which aspects of the seismic are the most reliable, and where, then only focus on these when comparing synthetic and seismic. A step-wise methodology has been defined to focus our analysis and link observations to specific changes to make in the model. The idea is that one would only proceed once each criterion was satisfied. The steps are: 1. Address inconsistencies at well locations using criteria 2 and 3 (before moving away). 2. Compare the predicted model surfaces in time with the equivalent interpreted time events that were used to build model. The time-thickness of the model “zones” should be consistent with the time interpretation. Mismatches are directly related to rock volume. Larger mismatches are most likely due to layer thickness. 3. Examine loop-to-loop alignment (peaks to peaks and troughs to troughs) within the reservoir packages – the character tie. Misalignment can occur due to inconsistency in the thickness of seismically resolvable internal layers, or the vertical distribution of properties. 4. If seismic is of high quality, extract amplitude maps from synthetic and seismic and compare. The trends should be similar and maps can be used to determine if the lateral property variations are honoring the seismic information. 5. The process of “digesting” the differences provides the opportunity for dialogue between seismologist and geologist to more completely discuss how the model uses all the inputs – from seismic interpretation to usage of seismic inversion results, and linkage to geology and petrophysical evaluation. One of the surprising outcomes of 3D CtL has been an independent check of the petrophysical
evaluation of porosity, Vshale (net-to-gross), and saturations. These properties are used in the static model – and are, therefore, the basis for determining the rock property regressions needed to transform reservoir properties into acoustic properties. On several occasions, the process of determining rock properties identified inconsistent petrophysical evaluation between wells, which was corrected before being used in model. Examples and lessons learnt along our CtL journey will be shared to illustrate key points.
-
-
-
Successful Application of Thin Bed Petrophysical Evaluation Workflow in Deep-Water Turbidite Environment: Case Studies from Fields Offshore Malaysia
As the demand for energy increases, oil companies are moving further offshore in their search for hydrocarbons in previously untouched deepwater reservoirs. In a deepwater turbidite depositional environment, high net to gross reservoirs are often overlain by a significant thickness of low net to gross sandshale sequences. While conventional formation evaluation, performed using standard resolution logs, is sufficient to characterize the thick high net to gross beds, it tends to underestimate and often fails to realize the
true potential of the low net to gross thinly bedded intervals. These thin bed packages, by themselves, can contain significant amount of hydrocarbon. Clearly an alternative method of evaluating log data in thinly bedded reservoirs is required for accurate assessment prior to commercialization. This paper presents case studies from several deepwater turbidite fields offshore Malaysia, where a thin bed petrophysical evaluation workflow has been successfully applied. The study was conducted as part of an integrated study to improve understanding of thin bed potential in terms of its distribution, lateral continuity and production capacity. The thin bed petrophysical evaluation workflow starts with a conventional formation evaluation; followed by constrained log-resolution enhancement processing; an enhanced resolution formation evaluation; cutoff selection for pay determination; and ends with core and formation tests calibration and validation. The results from the conventional and thin bed evaluation are compared to and validated by: core photographs; core x-ray diffraction analysis (XRD); routine core analysis of porosity, permeability and saturation; and formation test data. This paper concludes by highlighting some of the important advantages of using the thin bed
petrophysical evaluation workflow proposed, these include general and specific observations on: net to gross; saturation; volume of clay; porosity; and permeability. Finally recommendations are made suggesting logging programs to obtain optimal results from this thin bed petrophysical evaluation technique. Overall, this paper hopes to serve as one of main references for thin bed petrophysical evaluation in similar environment.
-
-
-
Stratigraphic Architecture and Process Variability of the Transgressive Paralic Cycle II (Early Miocene) Interval, D35 Field, Balingian Province, Offshore Sarawak
More LessDetailed and integrated core analysis (physical sedimentology, ichnology and biostratigraphy) and extensive well log calibration and correlation of over 70 wells (exploration & sidetrack), constrained by seismically-defined surfaces, reveal an intricate stratigraphic architecture of the Cycle II (Early Miocene) section of the D35 Field, constructed from coastal and marginal-marine depositional intervals. The overall architecture reflects a complex interplay and variability of sediment supply, relative sea level changes and depositional processes. Three major stratigraphic intervals are defined by lithofacies characteristics and fieldwide stratigraphic surfaces. The lowermost Interval I is defined by a field-wide basal erosional surface which partly truncates a correlatable coal-capped paleosol horizon in places, and overlies a prominent condensed section. The erosional surface is interpreted as a sequence boundary; it marks a significant fall of relative sea level across the field. The surface is overlain by a thick interval (> 100 ft) of sand-rich progradational unit; it is dominated by cross-bedded sandstones and pebbly-sandstones, which are interpreted to represent a coastal mouthbar complex, which in places are channelised. These cross-bedded sandbodies are interbedded in places with brackish, bioturbated (with several Glossifungites intervals) and wavy-to-irregularly laminated tide-influenced sandstones, indicating that the mouthbar complex is in contact with a brackish water body, and is affected by intermittent marine flooding. This interval is the distal, Lowstand System Tract. A major flooding surface, correlatable across the field, separates the Lowstand Interval I from the overlying Early-to-Middle Transgressive Interval II. This comprises aggradational-to-retrogradational units of laminated-to-massive, brackish estuarine mudstones, interbedded with tidal flat and minor bay head delta sandstones, often capped with minor coals and paleosol horizons. The stratigraphic and cyclic stacking of brackish mudstones-paleosol-coal facies association signals recurring marine flooding and land progradation throughout the deposition of Interval II, with minimal sand input. The Late Transgressive Interval III is characteristically marked by the dissappearence of coal-capped parasequences, and the domination of thick brackish estuarine mudstone. It is distinguish from the E-TST in many wells by the last coal before thick mudstone interval. A Maximum Flooding Surface separates the L-TST from the Highstand System Tract (HST). This is marked by the return of the coastal and estuarine margin, coal-capped parasequence set. The HST here is thin and poorly developed, or has been eroded by the subsequent fall in relative sea level, which forms the upper bounding surface for Cycle II and the Sequence Boundary for Cycle III. This truncation surface marks the end Cycle II.
-
-
-
Deepwater Thin-Bed Depositional Settings : A Geological Framework from NW Sabah
More LessDeepwater clastic depositional systems can have various thin-bedded depositional elements from a variety of settings. A systematic geological observation and classification using image-logs, cores and conventional/ sharpened logs, from the K Field, NW Sabah Province has been performed in this study. The thin-bedded deposits were looked at to assign depositional settings which could be one of several environments like proximal and distal levee, passive channel-fills and distal sheets. Available core demonstrates visible sedimentological characteristics like grain-size variations and trends, nature of bedding contacts, bedding-density and trends, sedimentary structures and post-depositional imprint. These observations when integrated with log and borehole-image response, at various scales, allow for a geological framework of thin-bed groups within the study area. The thin-bedded intervals typically lack the Bouma Ta division and commonly comprise of the parallely laminated Tb and rippled Tc divisions along with ome Td-e divisions, in combination or in isolation. The occurrence of these sedimentary beds in association with other features like mud-clasts, convolute-bedding, and climbing-ripples is indicative of the affinity of these beds to belong to one thin-bed depositional setting versus another. Core-based observations when calibrated against OBMI image-logs become a strong geological tool to help propagate validated observations into other wells or uncored intervals, where only image and log data is available. With these fine-scale observations it has been possible to package thin-bedded zones into genetic units at a coarser scale. These units are bound by surfaces that show distinctive breaks in well-log signatures and are potential strong reflectors in the seismic domain. It is possible to generate a model that predicts the stacking of these genetic units which are related to the cyclical depositional style in deepwater settings, primarily driven by relative sea-level fluctuations. A commonly observed cycle of deposition in deepwater during one lowstand cycle starts with mass transport deposits (MTD) at a sequence boundary, overlain successively by thickly-bedded good quality sheet sands followed upward by channel-levee-overbank complex capped by a condensed section (Fig. 1). In the K Field area this cycle is clearly seen. Mass transport complexes (MTDs - thickness range ~30-100m) are overlain by thick-bedded well developed massive sands (ThkSstn - thickness range 10-30m) which is followed upward by thinly-laminated sand-shale heterolithic package (thin bedded turbidites, TBT - thickness range 30- 100m) with variable net:gross (Fig. 2). H43 H86 Accommodation space in the toe-of-slope and proximal basin-plain controls facies distribution and architecture. Sea-floor radient, sea-floor mobility and rugosity, sedimentary budget and volume, net:gross in the system controls the type and distribution of accommodation space (Prather, 2001). In the K Field area local sea-floor rugosity is created by deposition of MTDs during early lowstand, which leaves an uneven depositional plain on the sea-floor. Following this event, typically a sheet-like well-developed sand unit is laid down which partially ponds the local sea-floor rugosity in the form of thickly-bedded sand packages, i.e. ThkSstn. Thereafter a graded to nearly graded system takes over, during which a channel-levee overbank complex forms which deposits thin-bedded turbidites, the TBTs (Fig. 2b and Fig. 3). This system is somewhere between the two extremes of a graded basin-plain setting and a successive fill-and-spill slope minibasin. Another category of sea-floor topography other than rugosity created by MTDs, albeit at a much slower but bigger scale, is attributed to active tectonic compression of the basin and the creation of toe-thrusts and the associated relief. The effect of this tectonic imprint on the sea-floor and hence on the depositional architecture is not very clear on the reservoirs of interest in the K Field area. The thinly-bedded (TBT) packages have been observed to represent two classes, one is high net:gross sand-shale package and the other is a low net:gross sand-shale package. Both classes are inferred to represent levee-overbank complexes, with the former being proximal levees and latter distal levees. The sedimentary characteristics that support the thinly-bedded deposits to be levee-overbank deposits are as follows: • interbedded sand and shale package, occurring as heteroliths (in analogy with modern observations) • consistent, parallel stratigraphic dips without much variance (Fig. 2a), unlike the other units especially MTDs • parallel-laminated to ripple cross-laminated sands and climbing ripple cross-laminations having mostly Bouma Tb-Tc-Td units (Fig. 3) • rip-up mud-clasts • convolute lamination. The sedimentary attributes mentioned above are not all common in all the thin-bedded intervals but they are typically observed and are presented here in order of importance. The occurrence of thin-bedded turbidite sections within a lowstand cycle of deepwater deposits hold a
key for facies modeling, determination of depositional architecture leading to reservoir simulation and producibility estimates. Due to lack of good quality seismic, affected by shallow gas cloud effects, geobody xpressions are not always clear and high-resolution observations like image and core should be employed for reducing uncertainty in facies analysis.
-
-
-
The Major Trends of Palynomorphs Distribution in Three Fluvial Systems, Peninsular Malaysia
More LessThree fluvial systems on the west and east coast of Peninsular Malaysia were assessed in term of their palynomorphs distribution pattern. They were chosen on the basis of their contrasting depositional setting, accessibility, availability of supporting published data and extent of disturbance by development. The one on the west coast is tidal-dominated Klang-Langat River. The other two rivers are located on the east coast. The first one is Pahang River which is characterized by a huge sediment output and located on a wave-dominated coastline. The other is Sedili Besar River which also debouches into a wave-dominated coastline but with low sediment output. The study was conducted on 352 sea bed and river bottom sediment samples that were collected between April to December, 2007. Samples were processed using a standard palynology preparation technique and ‘spiked ‘ with Lycopodium tablet which allow estimation of the absolute pollen abundance. The data for mangrove and hinterland pollen are evaluated and presented separately, each as pie chart diagrams that depicts the relative abundance of palynomorph in broad ecological groups. For mangrove, the ecological groups are Rhizophora , back mangrove, Acrostichum and Nypa, while the hinterland pollen groups are freshwater, riparian, peat swamp, coastal, seasonal, kerapah and temperate. The trends indicate that pollen grains and spores, are widely distributed by mainly water currents and to lesser extent by wind. Overall, palynology tells us less about the local environment, but more about the nature of the local or regional landscape. Mangrove pollen from the coastal plain is transported upstream up to the upper reach of the tidal limit and downstream with the dominant stream flow, out to the sea. As a result, sediments in the offshore area contain pollen signals which approximately mirror the main vegetation character onshore. Pollen from the river sources may not travel far beyond the offshore as shown by a drastic decrease in pollen abundance in the offshore area. It appears that, in the offshore area pollen could have originated from other places and carried via tidal current and that they reflect the vegetation in those areas. Rhizophora group is more common in the west coast, reflecting the broader lower coastal plain and dominance of tidal influence. Away from the pollen source on both coastlines, the pollen abundance gradually decreases, demonstrating the effect of pollen dispersal by wave and tidal current. The hinterland pollen reflects the broader aspects of the landscape. This is indicated by the dominance of alluvial swamp pollen as opposed to peat swamp. The effect of ecological disturbances by development and plantation is also clearly observed in pollen distribution pattern.
-
-
-
Hydraulic Top Seal Failure – The Relationship Between High Pore Pressure and Hydrocarbon Preservation in Hp/Ht Regions
As drilling worldwide aims for deeper targets, particularly in High Pressure/High Temperature (HP/HT) conditions such as experienced in the Malay Basin, (e.g. Bergading Deep, Sepat Deep and Gulin and Deep-1 wells), top-seal failure represents a high risk due to reservoir pressures close to the fracture pressure. A new methodology has been developed to analyse hydraulic failure as part of the risking strategy for prospects in these HP/HT regions. Part of the risking strategy for prospects is an assessment of seal breach risk at top reservoir, i.e. when the seal may be breached by high pore fluid pressures causing hydraulic fractures in the top-seal. Prediction of seal breach through hydraulic failure involves pore fluid pressures reaching or exceeding the minimum stress plus the tensile strength of the seal rock. In a water-wet reservoir, the buoyancy pressure in the hydrocarbon phase is considered to have a minor influence on rock behaviour and hydraulic failure is most closely linked to aquifer pressure. It is therefore necessary to study both the aquifer and hydrocarbon seal capacity in order to assess seal breach risk. To assess seal integrity requires data to define pore fluid and fracture pressures. Fracture pressures and gradients can be derived from analysis of Leak-Off
Test data (LOT), which can be compared with fluid pressures, derived from direct pressure measurements such as, RFT, FMT and MDT data, to analyse minimum effective stress and seal breach capacity (Figure 1). In some basins data show that the overburden can be the least stress, particularly where derivation of overburden from density data has been done. Accurate derivation of a predictive fracture pressure algorithm should include a pore pressure/stress coupling ratio term (which relates pore fluid pressure to horizontal stress magnitude through poroelastic fluid-stress interaction). Sense would dictate that the smaller the seal capacity at top reservoir, i.e. the closer the pore pressures are to the fracture strength of the rock, the greater likelihood of loss of hydrocarbons via fractures. This relationship observed from examination of high pressure wells from the Central North Sea. Using hydrocarbon seal capacity has minimal impact on the delination of dry holes and discoveries (or certainly not with regard to the column lengths present in the studied wells). A similar relationship between pore pressure, least stress and preservation of hydrocarbons is observed in the Scotian Shelf, (Bell, 1999). In the Central North Sea example, analysis of aquifer seal capacity has been onducted at top reservoir, and also at two stratigraphic horizons within the overlying top seal. The most convincing empirical relationship is within the top-seal where, using a cut-off of 50 MPa (750 psi), and a dataset of 66 wells, 88% discoveries of the wells are discoveries in excess of the cut-off. Below the cut-off are a series of dry holes and some discoveries which are non-commercial (Figure 2). In other HP/HT basins such as Mid-Norway, Halten Terrace there is no clear relationship between seal capacity and hydrocarbon preservation, either at top reservoir or at shallower levels in the seal. The implication here are that in the Viking Graben and Mid-Norway regions, other (or additional to pressure) factors exist influencing top-seal failure. These controls are likely linked to difference crustal stresses, with the direction of maximum horizontal stress varying in relation to fault strike, for instance, in each of these areas. Crustal stresses are potentially a combination of ice-loading, isostatic rebound of the crust and rapid
sediment loading in the Plio-Pleistocene. Other factors such as top-sea lithology and thickness are also considered, therefore, to have an impact in hydrocarbon preservation. Also that hydrocarbon pressures do not strongly influence hydraulic seal failure, rather, water pressure exerts the main control. This paper will present the workflow which have been has been established in these studies, and how they can be applied to aid the de-risking of high pressure traps in areas such as the Malay and other SE Asia
Basins.
-
-
-
Cyclic Transgressive and Regressive Sequences During Cretaceous Time, Northern Zelten Platform, Sirt Basin, Libya
More LessTwo marines Transgressive and regressive cycles are recognized during the Cretaceous time, one is represented during Early Cretaceous, when the Sirt area was still an arch. In this cycle, the sedimentation had only taken place on the line base of the arch. The Jurassic sediments partially transgressed the arch but had their depositional edge on the flank of the arch. The other cycle is represented after the northern Tibesti-Sirt uplift collapsed in the beginning of the Early Upper Cretaceous and during the Upper Cretaceous (Campanian) time. The Maestrichtian Sea encroached from the North and further to design the first flooding surface in the area. Thick of dark grey shale (Sirt Shale) followed by deposition of shallowing upward regressive carbonate of the Kalash Formation were deposited in the troughs. The Sirt shale acts as both a seal and source rocks for hydrocarbons trapped in the Cretaceous reservoirs and underlying the Cambro-Ordovician Gargaf Sandstone. The Upper Cretaceous formations are Bahi, Sirt, and Kalash in ascending order. The top of the Kalash Limestone marks the Maestrichtian/ Danian boundary in the study area.
-
-
-
The Use and Methodology of Logging While Drilling Nuclear Magnetic Resonance for Enhanced Evaluation of a Complex Lithology Formation in a South East Asia Offshore Basin
More LessThere are inherent difficulties in obtaining an accurate economic reservoir evaluation in complex clastic lithology environments typical of the offshore sedimentary basins found in South East Asia. Often such an evaluation requires a comprehensive suite of wireline logs to be run. However the target lithologies in these basins can deteriorate quickly, leaving a borehole in poor and unstable condition, which presents clear risks to a wireline operation; in terms of success and data quality. The use of conventional LWD triple combo logs of Gamma-Resistivity-Neutron-Density could be an alternative evaluation solution. However the Gamma, Neutron and Density logs are lithology\mineralogy dependent measurements and various borehole environmental corrections are needed for accurate results. Uncertainties in grain density, mineralogy, clay content, particle size distribution and the unknown properties of both in situ and invaded fluids make accurate volumetric calculations difficult, while poor borehole conditions or excessive invasion further complicate the matter. Both Neutron and Density logs are limited to total porosity estimations and different assumptions, relying on local knowledge or expensive coring and laboratory tests, to accurately define the formation
porosity. Not only can Nuclear Magnetic Resonance measurements resolve uncertainties in formation porosity. In addition, they provide information on porosity components as clay, capillary bound and movable that are vital in yielding the quantitative estimations of formation productivity. In the LWD environment, the Nuclear Magnetic Resonance measurement is acquired not long after the formation is drilled, when least borehole damage has occurred and invasion is minimal, thus maintaining a high level of data quality. The Nuclear Magnetic Resonance (MagTrak) tool has a low magnetic gradient design that enables quality Nuclear Magnetic Resonance measurements under dynamic drilling conditions. The tool has been designed to have minimal impact on the drilling operations and can be programmed for multiple acquisition modes that can be changed down hole by “down-linking” surface commands. Though full memory data for detailed analysis and provision of a T2 distribution spectrum is available after the tool run, the tool can provide T2 spectral data in real time. Additionally, the tool does not contain any radioactive sources, making it a safe and green alternative to LWD porosity measurements that require radioactive sources. This paper describes how the logging while drilling Nuclear Magnetic Resonance tool was used to log a complex lithology in an offshore South East Asian well to determine accurate lithology\mineralogyindependent porosities and how the measurement provided additional valuable petrophysical parameters such clay volume, pore size distribution, irreducible water saturation as well as information on moveable fluids and an estimate of permeability. Further, we discuss the methods used on the logging while drilling data to refine
the conventional petrophysical analysis of the formation and how the Nuclear Magnetic Resonance data was used to provide an estimate of the productivity of the reservoirs in question.
-
-
-
3D Seismic Acquisition for Hp-Ht Exploration of Block Pm303: Technical and Hse Issues
Authors Patrick Ravaut and Jaflis Jaafar and Emilie RenouxTOTAL E&P Malaysia (TEPMY) is operator of Peninsula Malaysia Production Sharing Contract PM303 and PM324 since May 22nd 2008. TEPMY and his partner PCSB performed a 1650 sq.km Full Fold 3D seismic survey over the western part of the block PM303 in May-June 2009 with the CGGAlize vessel. The aim of this paper is to present preparation and efficiency of this very successful operation both technically and on HSE aspects. As first acquisition operation in Peninsula Malaysia dedicated for deeply buried HP/HT targets, TEPMY had a special care in both geophysical feasibility study and environmental/social issues. Geophysical parameters definition started in TOTAL HQ in France in July 2008 and was mainly based on in-house re-processing of existing 2D seismic data and first interpretation of 2D data on this area. Main outcome were: - Survey design with long acquisition lines dedicated to cover main prospective areas but also to reduce line-change time and then cost, - Source and streamer depth deep enough to optimize Low Frequencies content for deep targets, - Streamer geometry: 8 to 10 of 6000m long to get far offset deep enough, - Recording length of 9s TWT in order to obtain a full image of the basin to understand pressure distribution at a semi-regional scale in an HP/HT domain. The Call-For-Tender was launched in December 2008 using TOTAL SA Standard contract. CGGVeritas was awarded the acquisition contract in early May 2009 with CGGAlize vessel in a 10 streamers configuration.
Environmental and Social Impact Assessment study was done by Environment Resources Management (ERM) as a TOTAL SA standard. Impact on fishing activity was the main result of this study as many fish-traps exist on the area and will have to be removed to perform safely the seismic acquisition. Recommendation was to communicate on the seismic survey with Local Authorities and Fisheries long enough before the starting date. But also considering having a Fishing Liaison Officer and fishermen
representatives onboard Chase Vessels before and during the seismic 3D acquisition. After meetings and discussions with Local authorities and fisheries, PCSB and other experienced operators, TEPMY and CGGVeritas decided to perform a fish-trap survey prior to shoot the 3D seismic. Five weeks before the anticipated start of the survey the first phase of the fish-trap survey was launched. First phase was dedicated to identify and tag existing fish-trap within the Safe Navigation Area (SNA). More than 100 fish-traps have been identified and tagged. At the same time flyer in different languages (Bahasa Malaysia, English, Thai and Vietnamese) were produced and distributed to a maximum of fishermen. The Indah-3D Seismic Survey started on the 20th of May with a total of 8 vessels: CGGAlize, Supply boat (Main Port Oak) and 6 chase vessels with more than 130 people onboard. Full acquisition last only 5 weeks with an average daily production of 60sq.km. TEPMY had 3 representatives onboard the CGGAlize: 1 geophysical supervisor, 1 navigation supervisor, 1 Marine Mammal Observer - who was also TOTAL HSE Rep on-board -, 2 Fishing Liaison officers onboard Chase-Vessels and 1 full-time experienced operation geophysicist in TEPMY office, for the survey follow-up. We also performed an Audit/Start-up mission at beginning of the survey with TOTAL HQ specialists during the full first week of the project. On more than 70,000 man-hours no LTI has been recorded and only 1 Medical Treatment Case occurred during a safety drill. In order to minimize impact on fishing activities the removal of fish-trap was done independently on each of the three Swaths. No problem was encountered with fishermen during the project. The project recorded only 59 hours of stand-by and 50 hours of down-time. 34 hours of stand-by time are related to 1 fish-trap in part of a streamer and down-time to small propellers problem. The acquisition operation is considered very successful thanks to: A good preparation, involving all parties, a good supervision, a good management of fishing activity, a good production of the CGGAlize, achieving a Job Efficiency of 93.3%.
-
-
-
Logging While Drilling Images Provide Feature Recognition as an Aid to Evaluation of a Fractured Granite Basement Reservoir
More LessThe evaluation of unconventional reservoirs, such as fractured granites, has become more important as the more common sedimentary reserves become harder to find. In Vietnam the majority of the country’s hydrocarbon production comes from fractured granite basement, making evaluation of this reservoir type an essential part of the country’s hydrocarbon exploration programme. Much work has been done on finding the best methods to appraise and quantify these reservoirs, as more traditional logging methods, primarily developed for sedimentary basins, are unable to fully characterize their unique petrophysical properties, due to uniformly high resistivity, very low matrix porosites, and widely ranging neutron and density measurements. The key to a full evaluation appears to be the measuring and mapping of natural fractures, and determining which of these are critically stressed; as it has been found that these are the main source of commercial pay. High resolution borehole images are ideally suited for this task, as they not only serve to identify natural fracture orientation, but also provide the most valuable, if not only, information on local stress directions. This paper discusses the use of a high resolution Logging While Drilling (LWD) electrical imaging tool as an aid to evaluating a Vietnam granite basement reservoir. The image produced was used as the reference for a fracture characterization study, in order to identify and map natural and drilling induced fractures. The identified fractures were used as input for a geomechanical analysis, including calculation of local stress directions. The two studies were then combined with recommendations on the preferred drilling trajectory to intersect natural fractures likely to be conduits to fluid flow, and examine any possible additional benefits from utilizing a high resolution LWD image in evaluation of fractured granite basement.
-
-
-
An Insight into the Tectonic Framework and Structural Evolution of a Frontier Area in Sarawak Offshore Basin, Malaysia
More LessTectonic framework and structural evolution controls the sedimentation of petroleum system elements in a basin. The present study integrates the results of offset well analysis, regional seismic mapping, and gravity modeling, to bring out a better understanding of the tectonic framework and structural evolution of a frontier area in offshore Sarawak basin. Regional depth structure and isochron maps based on reprocessed 2D seismic data were analyzed to characterize the structural fabric of the study area. Depth structure map at basement top reveals a strong overprint of the reactivated, NW-SE to N-S younger trend, over a less distinct NE-SW older trend, especially in the eastern half of the study area. The NW-SE trend is consistent with the regional lineation and the
basement high features, interpreted on regional Bouger gravity anomaly maps. The basement map, output from 3D inversion of free air gravity data over the study area, also corroborates these structural elements. Four distinct structural high axes, designated Trend1 to 4, aligned NW-SE to N-S, have been identified in the eastern half of the study area, on depth structure maps at Middle Miocene Unconformity (MMU), and Base Pleistocene levels. Trend 1 towards west, is aligned along the West Balingian line, a
regional strike slip zone recognized in the shallower part of this basin. West of this zone, no significant tectonic elements have been observed, other than the NE-SW trending faults, resulting from an earlier phase of extension. The other three structural high axes identified are located between Trend 1 to the west, and the West Baram line to the east. The alignment of the structural high axes along older basement trends, suggests basement involved structuring related to wrench tectonics. Isochrons of post MMU sequences indicate a progressive shift in the timing of wrench activity, from Late Early Miocene (?) towards west at Trend 1, to Recent towards east at Trend 4. Further studies are required to explain the causative mechanism. The study has helped in understanding the timing of the structures with respect to hydrocarbon migration, and has a direct bearing on the hydrocarbon prospectivity of the study area.
-
-
-
3D Prestack Depth Migration with Compensation for Frequency Dependent Absorption and Dispersion
Spatial variations in the transmission properties of the overburden cause seismic amplitude attenuation, wavelet phase distortion and seismic resolution reduction on deeper horizons. This poses problems for the seismic interpretation, tying of migration images with well-log data and AVO analysis. We developed a prestack depth Q migration approach to compensate for the frequency dependent dissipation effects in the migration process. A 3D tomographic amplitude inversion approach may be used for the
estimation of absorption model. Examples show that the method can mitigate these frequency dependent dissipation effects caused by transmission anomalies and should be considered as one of the processes for amplitude preserving processing that is important for AVO analysis when transmission anomalies are present.
-
-
-
InnoExtm - Innovative Exploration Concept
More LessGeosat Technology has developed InnoExTM, an integrated exploration approach. The underlying principle is to use various exploration technologies in order to maximize the exploration accuracy and to reduce exploration and subsequent development costs and risks: The InnoExTM key phases are: 1. Phase 1 :GEOSAT remote sensing analysis: three(3) independent methods are used to define hydrocarbon prospects :
• Structural lineament analysis: Systematic search for linear objects through an automated process -
computer program (SLARD)
• Analysis of thermal infrared images
• Spectral analysis: Analysis of multi-spectral space images for the survey of hydrocarbon deposits are
connected with the determination of specific anomalies of spectral brightness. Specific anomalies are
caused by up-streaming fluxes of water and gases that affect the temperature of the field.
• Additional available data will be incorporated:
o Geological data
o Lithological data
o Geophysical data
Basic principle is the determination of structures which have an active hydrocarbon system. These active hydrocarbon systems can be detected via the quantification of micro-seepage on the surface with its various characteristics. After the data selection, and data processing, the results of the three(3) independent methodologies are superimposed and interpreted and special hydrocarbon assessment maps created. Scope of phase 1 is to identify prospective hydrocarbon areas that should be further analyzed. By this approach areas for further ground evaluation and exploration can be reduced to 10-15% of the initial survey size. Hence the high graded prospective areas thereby identified qualify for additional ground works that are subsequently effectuated through phase 2 of our InnoEx approach: The application of 5 non-seismic methods over the high graded areas determined through phase 1: 2. Micro-Biological and Geochemical method (MBGE) (ground work): known as Microbial Oil Survey Technique 3. High Resolution Ground Magnetics (HRGM) (ground work) testing for distinctive magnetic signatures of hydrocarbon reservoirs. 4. High Resolution Ground Gravity (HRGG) 5. Magneto Telluric (MT) (ground work) for measuring low frequency currents in the Earth’s crust and
determining the type of sub-surface structure encountered: minerals, petroleum reservoirs, geothermal fields, ground water, etc. 6. High Resolution Geo Electrochemical (HRGC) (ground work) to determine the exact drilling point of oil and gas prospects detecting the metallic ion anomaly of the surface (High Resolution Geochemistry) All ground works are carried out in cooperation with companies specialized in this field. The data collected is then processed. Currently Geosat is developing a specific software to enable the combined analysis of the data from the different key phases. Based on the results of the Geosat study and the complementary non-seismic ground work the seismic acquisition program will be carried out over the predefined areas with an already proven active hydrocarbon system. The result of this analysis concept is a highly cost effective method that combines data from various independent exploration technologies to complement the seismic methods, fine tuning the interpretation and making the drilling and testing stage more accurate and focused. The variables and their interpretation (weighting etc.) can be easily adapted to the changing circumstances; the multifaceted technological approach guarantees a higher accuracy and increasing exploration success quotes. The result of this EXPLORATION concept is a highly cost effective method that combines data from various independent exploration technologies to complement the interpretation of the acquired seismic data and making the drilling stage more accurate and focused. This technological approach guarantees a higher accuracy and is increasing exploration success rates substantially.
-
-
-
Performance of Horizontal Wells of Bentiu-3B Sandstone Reservoir of Greater Bamboo Field (Block-2, Sudan) in View of Very High Viscosity of Oil and Profile of the Horizontal Wells – Case Study
Authors Kush Raj Keshari Singh and Elamin SulimanApproximately 100 mmbbl 2P OIIP has been established in Bentiu 3B sub layer of Greater bamboo fields by various exploratotory, appraisal and Development drilling. The vertical variation in viscosity viscosity from Bentiu 1A to Bentiu 3B has been the challenge for the exploitation of established reserve by conventional wells. The exploitation strategies in Greater Bamboo Fields were conceptualized to develop the Bentiu-1 and Bentiu-3 layers separately in view of high viscosity contrast. A number of horizontal wells have been drilled to optimally exploit particularly high viscous Bentiu- 3B reservoir. Since the viscosity of the Bentiu-3B reservoir is extremely high it was decided to carry out performance study of some key wells completed as horizontal well. An attempt is made to analyse the performance of these key well completed in highly viscous oil bearing Bentiu-3B sub layer and its relation to the Horizontal well profile, proximity to the Oil Water contact, Reservoir quality in the Horizontal well, Shale layers within the Horizontal well, and the fault as well as edge water in the proximity. The paper discusses the technical details of four cases of which two wells belong to each Bamboo West and Bamboo Main fields. In the Bamboo West both the wells has been analysed in detail and it has been found that in one well the TVD was gained more resulting to the proximity to the OWC whereas the other well was planned at the edge of the structure and close to OWC and fault. In the Bamboo Main one well has been drilled in zig zag profile which has no reason based on the all available data analysed. This type of horizontal wells, although planned suitably, if not drilled perfectly result in the poor performing well. The option of sidetracking could have been better option and saved the well from disaster. The other well drilled had poor data control from the nearby well. The well trajectory was planned up dip but when drilled, initially the trajectory was up dip later become down dip. The performances of the horizontal well are greatly affected by the drain whole profile in the exploitation of high viscous oil. If the profile of the Horizontal well is maintained as gaining TVD profile i.e. down dip profile the tendency of the water to move up will be relatively lowered. This has been observed in the analysed horizontal well but their proximity to the OWC has made them more water prone. The horizontal wells drilled with Zig Zag profile, even at the best place of structure are the poor performer whereas the wells with up dip (loosing TVD Profile) may perform initially better due the structural advantage but they are susceptible for water hold up and ceased production. The paper recommends various processes and way forward to drill horizontal wells and exploit this high viscous oil of not only Bentiu-3B but also similar reservoirs.
-
-
-
Passive Seismic Tomography: A New Era for Hydrocarbon Exploration
More LessPassive seismic plays an important role in the investigation of the interior structure of the Earth. Passive seismic is a 3-D seismic imaging of the target geology without using artificial surface sources. It uses multi-component seismic receivers to take advantage of shear wave energy generated by the microearthquakes thereby delivering a shear wave (Vs) velocity distribution estimate of the subsurface in addition to the conventional compressional (Vp) image. Recently, the passive seismic tomography surveys became an essential tool for the oil industry and modern reservoir management. The passive seismic technology is applied to investigate the relatively shallow depths that lie in hydrocarbon exploration window. In addition, some of the problems that are encountered in the conventional seismic explorations, for example salt domes effects, are solved using this technique. Passive Seismic Method constitutes the passive seismic transmission tomography in which 3-D images are created using the observed travel time of seismic signals originating from micro-earthquakes occurring below the target; and passive seismic emission tomography where the micro-seismic activity itself becomes the imaging target. The most straight-forward approach is to observe and record the direct arrivals of the seismic waves from these events and to map the distribution of hypocenter locations. Passive seismic technology, as an imaging and processing technique, challenges the following issues:
1. Identification of anisotropic flow and well targeting.
2. Determination of the three-dimensional VP and VP/VS velocity structure.
3. Analyzing the seismicity.
4. Getting under salt formations.
5. Description of the deformation processes of the reservoir.
6. Delineation of leaky fault structures, mapping active and conductive fractures of faults, at an
intermediate scale between borehole imaging and 3-D seismic imaging.
7. Predictive reservoir models thus Reducing uncertainty.
The Gulf of Suez, Egypt, is characterized by its high hydrocarbon potentialities where most of Egypt oil production comes from. The basic problems in exploration at the Gulf of Suez come from its complex geologic structural setting as well as the presence of anhydrites that mask the structures below. Therefore, Passive seismic transmission tomography (PSTT) creates 3-D images using the observed travel time of seismic signals originating from micro-earthquakes occurring below the so masked structures. The cost/benefit justification of 3D seismic applies to Passive Seismic. Deeper pool tests drilled with this coverage will have a much higher success rate. Coverage will provide risk-reducing information content. For example: new interpretation could prevent drilling of unsuccessful step-out wells ($1 MM savings per well). Additionally, PSTT may be the only viable seismic option for certain areas. One of the most important parts of the passive tomography investigation is the quality control of the results. This can be done using many different procedures and their correlation can lead to safe conclusions about the resolution power of the dataset and therefore the quality of the tomographic inversion results. The method used does not only verify the estimation of their accuracy, but also points out the areas of higher and lower analysis precision, thus making it easier to control the interpretation of the results. This paper represents the passive seismic technology as an alternative to the conventional seismic exploration for delineating the structures that are masked by salt domes and Anhydrites in the Gulf of Suez and other regions, as well.
-
-
-
Depth Trending – Predicting AVO Variability with Depth
Authors B. Hardy and H. Morris and O. PakpahanIn the quest for finding hydrocarbon reserves we continue to push into the deeper waters whilst looking at stacked reservoirs of deeper prospects. With increasing cost of wells we need to attempt to increase our confidence in the understanding of rock properties and the expected seismic signatures. Depth trending is a technique that uses our understanding of the rock physics and depth dependent behaviours gained at the wells and applies this throughout the seismic cube. Differential compaction behaviour of sand and shale lead to differing depth trends in these two lithologies. Understanding the cross-over point in acoustic impedance for these two lithologies is critical in predicting the AVO response. Depth trending allows us to predict the Vp, Vs and Rho trends of differing lithologies and gain an understanding of cross over points. This knowledge can be used to extrapolate our well data both horizontally and, more importantly, vertically which allows us to make predictions for AVO response at basin scales for plays deeper than current drilling. With the use of various data population techniques, reasonable predictions can be made even in areas with a low amount of wells. In this paper we describe a ‘best practice’ method for depth trending, including fluid substitution in
order to increase data population before comparing different exponential curve fitting algorithms. (Figure 1) Depth trend curves were created for shale, brine sand and gas sand lithologies. These depth curves are then used to predict AVO response for shale on brine and shale on gas interfaces for various depths (Figure 2). We also explore other applications of depth trend data. We forward model using a pseudo well and create a synthetic seismogram. By matching the seismic and synthetic we increase confidence in an undrilled hydrocarbon prospect (Figure 3). Finally we show how depth trend analysis can be combined with Monte-Carlo analysis to form probability distribution functions (PDFs) for various elastic parameters. This can later be used to form Bayesian Classification schemes leading to Facies distribution cubes.
-
-
-
Rock Physics and Reservoir Characterisation of Dolomitic-Sandstone Reservoir
Authors H. Morris and B. Hardy and E. EfthymiouRock physics is the bridge between all well and seismic data that allows us to better understand the sub-surface data. It is from this understanding that we can forward predict into the reservoir characterization of static models. We present here a simple but robust workflow, which allows the geoscientist to understand and capture the variability in the reservoir with the use of rock physics, forward modelling, seismic data conditioning, Joint Stochastic Inversion and Bayesian Classification. By understanding the variables that influence the seismic elastic and AVO signatures, the geoscientist can predict these variables away from the well (to provide evidential fluid fill and lithology variation) and therefore produce more accurate static models. The forward modelling of the various scenarios gave the interpretation team an understanding of the effects under various conditions (brine, gas, high porosities and low porosities). It identified that it would be possible to separate out the lithology effects and the fluid effects, preventing a mis-interpretation, and an insight into where the inversion results and classification would lead (Figure 1). The Data Conditioning of partial stacks proved to be an essential part of the workflow, allowing making the gradient stack a coherent volume rather than a volume dominated by noise. Calibrating the background AVO seismic signature to the wells meant that the synthetic (Figure 2) and seismic responses were aligned in their properties in and around the reservoir. The ability to optimally condition partial stacks
rather than raw gathers meant that the time and cost was greatly reduced, giving operational flexibility. A comparison of a conventional Bandlimited inversion versus the Stochastic Inversion highlighted the weakness of the Bandlimited inversion to capture the detail required due to resolution issues. Stochastic Inversions are an integrated modelling method and are capable of capturing or including very high resolution detail from the well. By using a relatively coarse sample rate of 2ms we were able to prudently predict below standard seismic resolution, and therefore the seismic data drove the inversion rather than geostatistics. Whilst there were discrepancies between the realizations, a consistency in general supported a strong inversion result and a common answer. Acoustic and Gradient Impedance were fundamental in the reservoir characterisation, and the Elastic Impedance acted as a good QC of the inversion prediction and results. The Bayesian Classification and Rock Physics Model calibrated methods both showed similar results in predicting pay vs. non-pay areas, with the Rock Physics Model providing a possibly more refined final result. The overall method shows a robust and coherent approach to understanding and predicting the reservoir characteristics.
It also allowed us to gain confidence in predictions of proximal prospects. The use of the stochastic inversion and Bayesian classification and Rock Physics Models to constrain and calibrate the inversions gives the results enhanced meaning in terms of reservoir properties. The rock physics to reservoir workflow produces a sophisticated high resolution static model which integrates all seismic and well data into one workflow from the basic interpretation through to dynamic modelling (Figure 3).
-
-
-
Field Development Planning for Coal Seam Gas: Challenging the Paradigm
Coal Seam Gas (CSG), alternatively known as Coal Bed Methane (CBM) is one of the exiting new energy plays emerging in the Asia-Pacific as well as elsewhere. CSG reservoirs and reservoir behavior over time are very intrinsically different from conventional plays, therefore conventional field development planning workflows need to be modified to address the focus issues and decisions relevant for CSG: number and type of wells required to achieve the committed gas delivery, timing of development startup taking into account anticipated range in dewatering time, optimum development phasing, optimum facilities layout, mitigation strategy to cover the key downside risks, as well as flexibility required to cater for upside. To date, CBM developments have typically followed a ‘low tech’ approach of pattern drilling with limited emphasis on subsurface studies and instead, a strong focus on ‘on-the –fly’ optimization of the wells and completions concepts. We believe there is potential to overhaul the traditional ways of going about CBM developments by using modern subsurface study and uncertainty management techniques to aid in upfront concept optimization (Figure 1). Objective of this paper is to illustrate this potential and some of the workflows and concepts involved.
As with conventional developments, reservoir characterization and modeling are a key component of the FDP study workflow. A lot of the focus is on mapping the distribution and properties of the reservoir rock. However, in a CSG play coal is the reservoir and gas storage is not in a conventional pore system but adsorbed on a molecular scale onto the internal surfaces of the coal. The reservoir properties that matter for GIIP and UR calculation are therefore different from conventional and include net reservoir (= coal)
thickness, isothermal coal properties (which control the gas adsorption & desorption capacity of the coal), impurities content (i.e., ash and moisture), gas content (i.e., saturation) and permeability of the natural fracture system in the coal. CGS developments to date are typically onshore, shallow and therefore drilling intensive. The wealth of well data brought about by such intense appraisal and pilot development drilling opens the door to elaborate geostatistical analysis as an effective means to highlight spatial trends and variability, deliver multiple realization maps and 3D models of each of the relevant reservoir properties, as well as to recommend optimum appraisal strategy and location. Rigorous analysis of the fracture system via integration of fracture spacing/orientation data from core and scanner tools with welltest results and seismically mapped structures can reveal key clues on permeability and connectivity of the coals. Maps of fracture orientation combined with (sub)seismic faulting can also aid in optimizing well placement. Because GIIP and UR equation is different from conventional, adaptations to existing modeling tool functionality are required to facilitate CSG volumetric computation. Like their conventional counterparts, CSG static reservoir models are then upscaled and transferred to dynamic simulation to establish optimum well count and spacing, predict dewatering time and required water handling capacity, and determine the optimum balance between wells and compression. We have developed fit-for-purpose workflows and toolkits to facilitate data transfer from mainstream static modeling tools to the specialist dynamic modeling packages that can adequately forecast CSG production.
-
-
-
Diversity Equals Opportunity: The ‘Romance’ of NE Sabah’s Shelf
Authors S. King, P. Restrepo-Pace, R. Jones, C. Goulder and Y. Ah Chim and C. RussellFluctuating oil prices, threshold economics and changing corporate strategies are all too familiar ‘constraints’ that drive companies into or out-of exploration areas. These factors are many times just as unpredictable as some of the elements of a given petroleum system. Regardless, it is a well known fact that the greatest asset of an exploration company is a diverse portfolio of drilling opportunities, with large upside potential. The geology of NE Sabah’s Shelf offers just such potential. The area is on trend with a prolific petroleum province exhibiting a 30% historical exploration success rate and delivering a 70% oil versus gas split. Recently acquired 2D and 3D seismic data, together with extensive palaegeographic reconstructions and 3D burial history modeling have helped illuminated a range of geologically independent targets in the area, from amplitude supported structures in proven play types, to the romance of previously undrilled basins. The prospective succession in this area can be broken into four largely independent plays: 1. Mid to Late Miocene Deepwater Clastics - A slope canyon system trending WSW-ENE has been identified in the Kindu Sub-basin and several structural and combined structural-stratigraphic closures are mapped. The system is not intersected in any of the near offset exploration wells, but appears somewhat analogous to the South Furious 30 discovery. 2. Late Miocene Shallow Marine Clastics – A proven play on the Sabah Shelf, included stacked gas pay in Titik Terang-1 and stacked oil pay in the South Furious and Barton discoveries. The late Miocene play is DHI supported and several amplitude anomalies showing flat spots and fit to structure have been identified. 3. Pliocene Carbonate Reefs – An extensive carbonate reef system extends south from the Philippines on to the Sabah shelf. The reef system has been targeted by several exploration wells in the far north, with no success, probably due to an absence of local mature source kitchens. Further south however, several prominent un-drilled reefs have been identified. The reefs exhibit possible flat-spots and lie immediately adjacent to the proven Kindu Sub-basin kitchen. 4. Pliocene Shallow Marine Clastics - A thick succession of Pliocene deltaics has been identified in the undrilled Siagut Sub-basin at the very northern edge of the Sabah Shelf. The Pliocene deltaics remain largely uncalibrated by drilling, but based on seismic facies analysis appear somewhat analogous to the proven Miocene play further south. 3D burial history modeling also highlights the potential for oil generation from the Siagut Sub-basin.
-
-
-
Unmasking the Crest, Imaging Below Shallow Gas Using Prestack Q Depth Migration, Irong Barat Field, Malaysia
Seismic imaging of many oil and gas fields in Peninsular Malaysia is degraded by amplitude and frequency attenuation (Q) associated with shallow gas. In addition to the amplitude attenuation, seismic travel time delays caused by abnormally slow velocities associated with these shallow gas accumulations cause time structure distortions in the seismic image. These amplitude, frequency, and seismic traveltime distortions often obscure the seismic image sufficiently that seismic reservoir characterization is impossible. In some areas the seismic image is completely distorted and lost, in these situations conventional marine seismic P wave imaging is not an effective tool. However in other areas the seismic image is degraded, but seismic energy is still transmitted through the shallow gas attenuator. In these situations seismic processing technology can attempt to compensate for the image degradation. Using a Prestack Depth migration engine, we have developed a processing technique to recover the amplitude and frequency loss below these shallow gas zones. This technology uses an integrated Q model, velocity model, and depth imaging system to correct and restore the amplitude, frequency and velocity distortions associated with the shallow gas attenuators.
Initial implementations of prestack Q depth migration have shown that a detailed velocity and Q model of the subsurface is not the only requirement for a successful project. Since Q modeling requires the data to be true amplitude, most conventional approaches for noise attenuation and acquisition footprint removal cannot be applied prior to imaging. This requires the development of special noise mitigation techniques; otherwise the increased noise level can overwhelm the final imaging results. In addition, incorporation of the well data offers clues to the rock physics issues associated with the Q and velocity distortion. ExxonMobil recently completed the first prestack Q depth migration project in Malaysia over the Irong Barat field. A recently signed Production Sharing agreement for this mature field gives ExxonMobil and partner PCSB production sharing rights to 2033. Improved seismic imaging is part of the strategy implemented to recover remaining oil reserves for this mature field. The 142 square kilometer Irong Barat 3D
survey was acquired in 1998. The survey combines conventional marine data with OBC undershoot of the platforms, which adds processing complexity. Image quality on the flanks of the structure is very good, however varying degrees of shallow gas associated distortion are present over the crest of the structure and therefore Irong Barat was considered a good test for the Prestack Q Depth Migration technology. This paper will describe the seismic processing lessons learnt and present the results of the project.
-
-
-
Source Rock Evaluation in the Northern Dezful Embayment, Zagros, Iran
More LessIn order to evaluating some of the source rocks in Dezful Embayment such as Pabdeh and Gurpi 14 wells distributed in different oil fields from the northern Dezful Embayment selected and TOC % calculated by Δ log R method and neural network. Result compared with measured data (by Rock Eval). The result come from neural network have more correlation with measured data than Δ log R results. We calculated TOC % based on combination of resistivity , sonic and level of organic metamorphism(LOM).
In respect to Pabdeh and Gurpi F.m matured in some oilfields and parts of other oilfields, therefore we must calculated initial TOC, so we did oil generation modeling for getting E.Ro (equal Ro) , for calculation of transformation ratio(TR). Consequently, we could calculate initial TOC % and plot Iso TOC contour map in this area, and also make zonation Pabdeh and Gurpi formation based on geochemical criterions .
-
-
-
Influence of Pre-Existing Faults in Emplacement and Variation of Toc% in Pabdeh Formation Throughout Northern Dezful Embayment
More LessIn the petroleum systems ,understanding the process of sedimentation and paleogeography, which control the distribution and quality of source rocks ,reservoirs and cap rocks is necessary. Although climatic conditions, transgressions and regressions control the oxic and anoxic conditions but some geological settings and their structural history are considerable for sedimentation of source rocks. In this study ,using the neural network TOC value of Eocene pabdeh formation in northern Dezful Embayment is located in the Zagros petroliferous province is calculated relationship between TOC and basement faults was studied. The basement of Dezful Embayment is not integrated, and has staircase status. Northern part of this area is bounded by MFF(mountain frontal fault), ZFF(zagros foredeep fault) ,Balarud and Hendijan basement faults. The Separation of blocks by thrust faults caused differences in rate and type of sediments. Tectonic phases and depth variations have affected lithofacies pattern and in result of,They played role in organic content of rocks. The reactivation of faults specially in Hendijan lineament and vicinity to palaeohighs caused for increasing of geothermal gradient and maturation in pabdeh formation that presumably have led to enhance oil production locally and consequently, decreased TOC % in some oil wells.
-
-
-
Source Rock Evaluation in the Southern Dezful Embayment
By M. ShayestehWire line tools are known as advanced and economic methods for formation evaluation of depositional basins. Wire line logs and data can be used to recognition of oil generation potential in a source rock . source rocks exhibit various especial properties in wire line logs Also their ability to oil generation can be recognized by hydrogen percentage (as a qualitative indicator) and total volume of organic matter(as a quantitative indicator ). A method is known as "ΔlogR" organized for" TOC" calculation . Another method is for neural network. This article explain the usage of there methods in detail to determine the volume of "TOC" in different source rocks ( Papdeh , Gurpi & kazhdumi ) in Aghajari , Parsi , Pazanan & Karanj fields in the southern Dezful embayment.
-
-
-
Survey Design and Evaluation for Advanced Marine Acquisition in Geologically Complex Areas
Authors Åsmund Drottning and Endre Bergfjord and Mike BranstonThe goal of this study is to present a survey evaluation and design (SED) methodology that determines which strategy will give the best return on investment (ROI) for a geologically complex area, in this case a marine, sub-salt reservoir. The key objectives within this study are to characterize the impact each survey strategy has on the illumination of the target horizon, to quantify the improvement in seismic data quality and establish which strategy gives the best ROI.
-
-
-
Pipeseis VI VSP as Challenging Method for High Accuracy Target of Horizontal Well
Authors Tiur Aldha, Juniza Jamaludin and Gunawan Taslim and Anis ShahabThe Vertical Incident (VI) survey was designed to have the walkabove Vertical Seismic Profile (VSP) source positioned vertically above the downhole receiver in highly deviated well to insure that the direct arrival travel path from source to receiver is close to vertical. In early 2009, it had been used in one high deviated pilot well prior to drill horizontal well in offshore Malaysia where to place a good oil reservoir along the well path accurately. In order to maximize the data quality and to reduce the risk of getting the downhole receiver stuck in the hole, the survey was recorded using Multi Level Receiver (MLR) string consisting of 2 x three component fixed ESR downhole geophone receivers using the PipeSeis technique, whereby the receiver array is deployed inside the drill pipe. The accurate velocity information from this VI VSP helps make crucial decision for horizontal well planning and better resolution for fault imaging.
-
-
-
Geometry Charecterization in Ax Field
More LessThe Malay Basin is underlain by a productive, oil and gas-prone, nonmarine Cenozoic section. Characterising I Group channel morphology in AX Field is the main target of this thesis. A successful study of seismic geomorphology depends not only on knowledge of sedimentological, geomorphologic principles and the local geological setting, but also on quality of the seismic. 30x30 km three dimensional seismic surveys were used to study the stratigraphic record within I Group. Horizon slicing concept was used in this project; it depends on horizon and seismic data quality. Horizon slicing on full stack volume is useful in channel detection, while on structure volume is useful in channel width measurement. Straight and meandering channels are the main patterns recognized within I Group. Channels widths are ranging from 300m to 700m. Channels thicknesses are estimated using Spectral decomposition technique. The range of channels thickness is 20m-30m. Data of four exploration wells are useful to compare the real channel thickness with the estimated, when channels are drilled. Deposition environment within I Group is fluvial to tidal environment, means AX field is located close to the shore line at the time of I. Basin ward direction is to the east or south east. Seven main fluvial channels have been detected. Base of each fluvial channel considered to be sequence boundary. According to 3rd/4th order of sequence stratigraphy concept, eight sequences have been interpreted within I Group.
-
-
-
Fluid Facies Prediction Through Avo Inversion in Offshore Sarawak
Authors Yusliza M. Sufian and Yeshpal SinghAVO inversion and validation of seismic amplitude study was carried out in a Sarawak Block over two prospects for derisking. The main objective of the study is to integrate seismic, geological and well information for identification of hydrocarbon reservoirs over the prospects. AVO inversion is a relatively new technology in the industry and has potential to provide more quantitative information than conventional AVO analysis. The standard AVO analysis is used to improve the understanding of the subsurface and in reducing geological risk. However, standard AVO analysis has many disadvantages and often used qualitatively. In some cases, it may even produces false result due to amplitude tuning and qualitative match with forward modeling from well data. AVO inversion overcomes most of the said disadvantages of conventional AVO. It includes the integration of the best of inversion of offset/angle gathers simultaneously whilst exploiting the full information within the seismic, log and relevant geological information available in terms of structure as well as stratigraphy. Fluid facies prediction using 2D probability density functions (PDF) of inversion attributes was modeled at well locations. The pdfs are classified based on facies and applied on 3D inversion attributes to estimate facies probabilities and then most likely facies cube in the area of interest. Analyses are then validated by the hydrocarbon sand intervals of the drilled wells in the study area. Stratal slicing analysis along with 3D visualization helps in further refining the analyses. It can be noted that AVO inversion results helped in predicting probable location of hydrocarbon bearing sands and hence better well placement. One of the prospects was drilled based on the result and the post drilling results validates the predicted facies.
-
-
-
An Efficient Way to Characterize Complex Reservoirs Through Downhole Fluid Properties Measurement
Reservoir connectivity and compartmentalization are main challenges during the field development plan. High resolution logs and seismic interpretation are usually used to characterize reservoir complexity. However, similar to other interpretation methods, they have some degree of uncertainties. Reservoir pressure and fluid communications are therefore crucial to prove reservoir connectivity, especially in complex reservoirs. In offshore Peninsular Malaysia, oil field X has a big structure covering an extensive area with East- West elongated anticline and North-South trending faults. The reservoirs are tidally influenced mouth bars deposited within estuarine or bay fill environment. The reservoir fluid is known to have large variation of CO2, waxy, viscous, and low Gas-Oil-Ratio (GOR) based on the early appraisal well production tests. Currently, the field is undergoing a series of appraisal wells drilling program for delineation and reservoir data acquisition. Apart from the data quality, cost and timing are the key consideration for getting early reservoir fluid properties as the field is geared for the early first oil. The challenge is to obtain critical reservoir fluid properties such as CO2, GOR, fluid density, fluid compositions i.e. C1 to C6+, quickly and efficiently. This information is required for reservoir modeling and it can also be used to confirm reservoir connectivity in terms of fluid communication between fault blocks as previously interpreted in the structure map. The conventional approach of collecting downhole or surface samples during Wireline Formation Tester (WFT) or production test and then have these samples sent for lab PVT analyses is expensive and time consuming. It involves contract preparation and bidding, lab queue system and also subject to samples quality and handling risks. Alternative ways to obtain in situ reservoir fluid properties quickly, accurately and representative of the reservoir have been explored, used and tested in this paper. This work illustrates the use of Downhole Fluid Analyzer (DFA) data to better characterize reservoir fluid complexity in such a way that it can completely change the current perspective of reservoir fluids. The new generation of WFT together with DFA data allows us to accurately quantify the CO2 content which is essential for facilities and pipeline designs and material selections. In addition, this technology provides high quality real time fluid properties with significantly less contamination. This is an excellent alternative way to obtain high quality reservoir fluid properties without production test and laboratory analysis. The small variance between the DFA and the lab measured data has increased our confidence to extend the application of this tool in the appraisal wells program where no production test or fluid sampling is planned. This has led to the early understanding of the reservoir fluids system in terms of GOR, light ends and heavy ends components, density/API, viscosity, CO2 variations vertically and areally without having to conduct unnecessary production test or downhole fluids sampling. It is a cost saving in a way.
-
-
-
Application of High-Resolution Sequence Stratigraphy (Hrss) for Reservoir Prediction in Group L & M, Block Pm309, Malay Basin
More LessThe high-resolution sequence stratigraphic (HRSS) classification and correlation techniques, based on the principles of strata base level, volumetric partitioning and facies differentiation, can effectively improve the prediction of reservoir and increase opportunity of finding the subtle oil and gas reservoirs. Calibrating among core, well log correlation and seismic interpretation, identification of key sequence interfaces and reservoir mapping have successfully been applied to predict the distribution of effective reservoir in the Group L & M of Block PM309 in Malay Basin. This is the first detailed study done in Group L & M since its discovery and was conducted at the southeast of PM309, near Malaysia-Indonesia boundary. Seligi and Pulai are the two oil fields have been used in this study. The seismic stratigraphic units of Group L (younger) and M (older) were deposited in the lacustrine rift basin during the synrift phase. Below Group M, eight fourth order sequences were identified which mainly comprised of alternating thick sandstone and lacustrine shale packages. From Top Group M to L20 sand, two fourth order sequences were identified. The Group L facies include non-marine lacustrine offshore to deltaic, braidplain and minor lakeplain. Progradation of lacustrine sediments started from Top M up to the L70 sand. Above the L70 sand is a third order sequence boundary. Another third order sequence boundary was interpreted to be above the L20 sand. L20 sand package consists of thick laterally aggrading braided stream sandstone. Above the L20 sand, the younger sequences retrograde up to the top of the Group L. Twenty wells and four core description have been conducted in this study. Interpretation on L20 and M20 sand was done and correlatable with the well log. Based on the study, stratigraphic hydrocarbon traps was represented by sandstone bodies of deltaic and shoreface origin. From the deltaic environment, the traps are mostly from distributary channels and mouth bar bodies. The mouth bars (i.e M20 sand) were identified by their upward-coarsening trend from well logs and the deposition evolves mostly during the highstand systems track. Lacustrine shales act as seals to trap the hydrocarbon.
-
-
-
The Importance of Including Overburden and Survey Illumination Effects in Reservoir Seismic Simulation
Authors Åsmund Drottning and Isabelle Lecomte and Mike BranstonThis paper explores an alternative approach to 3D and 4D seismic modeling based on the SimPLI (Simulated Prestack Local Imaging) PSDM simulator technique introduced by Lecomte et al. (2003), Lecomte (2004), and presented in more detail in Lecomte (2008). The method is both computationally efficient, allowing quick, repeatable, multi-scenario analysis, and allows the integration of illumination constraints from the survey and overburden, making it particularly useful for time-lapse seismic analyses. The PSDM simulator is a rapid and cost efficient solution for realistic simulation of seismic data that goes far beyond classic 1D trace modeling and allows comprehensive sensitivity analyses by forward modeling in a time frame not afforded by Finite Difference Modeling (FD). The modeling concept and workflow was discussed by Gjøystdal et al. (2007). Here we present specific examples from synthetic models as well as a real data example from the Norne field offshore mid-Norway. These examples will focus on the integration of survey data, overburden properties, rock properties and fluid simulator data into the 3D and 4D seismic modeling schemes, and discuss their impact on the seismic responses.
-
-
-
Reservoir Characterization in the West Baram Delta Through Rock Physics Constrained Data Integration
Authors Yeshpal Singh and Kamal Arif B.M. Amin and Erick AlvarezIt is well established fact that seismically derived petrophysical properties provide a more complete description of the reservoirs than what could be done through the conventional statistical techniques based on wells and seismic maps. The main objective of present study is to determine which petrophysical parameters control the reservoir quality and how these are related to the elastic properties that control the seismic propagation. Constraining a geological model using seismic derived properties always represents big challenges, mainly because of the uncertainties associated with the seismic properties, and the differences in resolution of the measurements involved in the process. This can only be achieved if a complete and well organized integration between the different disciplines involved is achieved. We present the methodology and results that allowed conditioning the geological model using seismic derived properties in the Siwa field, Sarawak basin, Malaysia.
-
-
-
A Comparison of Porosity Modeling Involving Well and Core Data with AI from Inversion in Temana Field; A Case Study
Temana field is located approximately 30km offshore Bintulu which is in the Balingian PSC, subblocks 4Q-29 and 4Q-30 with the water depth of 96 ft. The field is divided into 3 hydrocarbon accumulation namely the Temana West, Temana Central and Temana East; each area has different deformation style and fault patterns (Figure 1.0). The Temana field was discovered by drilling the Temana-1 well in 1962 and brought into production in 1979. Temana Saddle has been discovered by drilling the appraisal well (Temana-72) in 2004. The outcome from the appraisal campaign indicated that the I-65 reservoir is the most promising reservoir compare to the other reservoirs in the Temana Saddle area. An FDP (Field Development Plan) study was initiated in 2005 and
the 1st oil from this study was in Q1 2006 (Figure 2.0). 3 new development wells namely Temana-73ST1, Temana-74ST2 and Temana-51 ST2 were drilled in Phase 1. The highest production was from the Temana- 73ST1 tested at ~3600 bopd and the accumulative production of 4.1 mmstb as of April 2009 (Figure 3.0). The dynamic simulation shows a pressure drop of ~250 psi and an increasing GOR trend approaching RMP limit (1500 scf/stb) was observed. The Phase 2 FDP study was started in 2007 after the completion of Phase 1 drilling and focusing on the pressure maintenance study. The study involves updating the static model by incorporating the new well data to update the STOIIP. The standard workflow of static modeling (involving the well and core data) is followed as in previous Phase 1 study (Figure 4.0). At the property modeling stage, the same algorithm was used but using 2 different methods; 1) to model the porosity based on the well data and propagated by variogram and 2) to model the porosity by incorporating the AI derived porosity data constrained with log derived porosity data. The main aim of this study is to compare the porosity distribution from both methods whether it does match with the porosity in the new post drilling well. The cross plot between well log porosity and AI gives a good correlation of 87% (Figure 5.0). From the study, the porosity model which was generated based on well data and propagated by the variogram give s a good porosity match with all wells (Method 1), where as the model that was generated based on the inversion (Method 2) give a good porosity match only at the well locations that have checkshot and sonic data, and fair to good correlation in the other wells (Figure 6.0). Volume calculation shows an increase of 28% and 17% in STOIIP using method 1 and 2 respectively (Table 1.0). In conclusion, AI derived porosity model must be used provided most of the wells have checkshot and sonic data to address the uncertainty.
-
-
-
Porosity Prediction from Acoustic Impedance (AI) in Temana Saddle
Temana field is located approximately 30km offshore Bintulu which is in the Balingian PSC, subblocks 4Q-29 and 4Q-30 with the water depth of 96 ft. The field is divided into 3 hydrocarbon accumulation namely the Temana West, Temana Central and Temana East; each area has different deformation style and fault patterns (Figure 1.0). In 2004, an appraisal well namely, Temana-72 was drilled in Temana Saddle area which is located in the southwestern part Temana Central. The outcome from the campaign indicates that the I-65 reservoir is the most promising reservoir compare to the other reservoir. A FDP ((Field Development Plan) study was initiated in 2005 and the 1st oil from was in Q1 2006. The Phase 2 FDP study was started in 2007 after the completion of Phase 1 drilling focusing on the pressure maintenance. A revised static model building incorporating three more appraisal wells information is the major objectives. Seismic data has proved to be a critical tool in predicting the reservoirs properties beyond the
limitation of the well control. The changes in seismic response could be related to changes of lithology, fluid contents or variation in reservoir properties. The used of seismic driven properties integrated with the well data are common in reservoir modeling building either as a trend input along with geometry constrained by structural interpretation. This paper will discuss on the inversion of the post-stack seismic reflection data into impedance data. Seismic and well integration workflow for reservoir model building as shown on the next page has been established (Figure 2.0). The inverted AI was transform to reservoir properties particularly porosity in Temana Saddle area. This seismic predicted porosity has been use as a trend input in reservoir model building together with the well log input to produce the 3D porosity model. Well log data QC analysis of Temana-72 indicates that porosity can be predicted from Acoustic impedance (Figure 3.0 and Figure 4.0). Predicted porosity can be used as trend input for reservoir model building in and around Temana -72 area. Correlation coefficient is 0.86. This study is done to provide a predicted porosity value for I60 and I65 derived by seismic data in order to proper propagate the porosity value between the wells in the reservoir model (Figure 5.0). The porosity prediction using the acoustic impedance give good result at the well location that have sonic and checkshot and fair to good correlation in the other wells.
-
-
-
Dual-Sensor Technology in Marine Seismic Acquisition Applied to New Play Identification in Central Luconia Province, Offshore Sarawak
More LessCentral Luconia Province in offshore Sarawak Basin has predominantly in the past been the target of numerous exploration campaigns. Past efforts in this tectono-stratigraphic province focused mainly on Miocene carbonate buildups (Cycle IV & V) ranging from platforms to pinnacles. Discovered fields, the likes of Bijan, Jintan, F12, F6, E8, PC4 and such have proven commercial quantities of hydrocarbons in the carbonates. The pre-carbonate clastic sequences have also been proven prospective but the exploration efforts to date have been impeded to a large extent by seismic imaging issues. PETRONAS has in the past, considered various technological advancements encompassing both acquisition and processing methods thought to be capable of illuminating the pre-carbonate plays. Advance processing techniques helped but the fundamental issues of energy absorption and dispersion rendering ‘wiped-out zone’ and severe seismic attributes attenuation below the carbonate still remain. The idea of dual-sensor (hydrophone and velocity sensors) technology has been discussed as early as 1964 by Schneider and Backus. Yet the issues of resultant noise from the vibration of towed streamer and sensors render the data unusable. Two different approaches were formulated for producing usable dual-sensor data; i.e. simultaneous towing of streamers at different levels and collocation of both sensors in the same streamer. PETRONAS opted to test the latter approach and seek to quantify the improvement in the seismic data image quality. To this end, a marine 2D seismic acquisition initiative utilizing dual-sensor technique was executed in Central Luconia area repeating vintage 1998 2D lines acquired conventionally. The original acquisition specifications were maintained as much as possible and both datasets were processed following similar sequences so that any improvement can be directly attributable to the differences in acquisition technologies. The primary target was imaging the pre-carbonate clastics at 1.5 seconds to 2.5 seconds in two-way time. Indeed, significant improvement of the dataset was observable through out. The amplitude spectrum shows marked differences between the newly acquired dual-sensor and reprocessed vintage 2D datasets. SRME procedure benefited from the wider range of bandwidth accorded by the dual–sensor technique dataset. In the examples, the differences both in the single shot gather and stack section are shown. Accurate Q estimation proves useful in preserving the deeper primary reflections. The dual-sensor dataset gives improved image of deep events as well as the capturing of more usable lower frequency data. Thus, we conclude that the technology is a workable step ahead in imaging pre-carbonate geology in Central Luconia Province.
-
-
-
Overview of Remaining Exploration Potential Plays in East Sabah Basin- Malaysia
Authors Robert Wong and Meor SyazwanThe East Sabah Basin consists of two sub-basins-the Sandakan sub-basins and the South Dent Trough. So far most of the wells drilled in the East Sabah Basin were focused on the northern part of the Sandakan sub-basin, targeting the obvious Middle-Upper Miocene deltaic play within structural closures. Some oil and gas were discovered so far with none of the fields developed yet. The paper will focus on the whole of the East Sabah basin which includes the Sandakan sub-basin and Sabah Trough. Within the Sandakan basin, the untested plays include the stratigraphic traps of turbidite sands which include slope fans and basin floor fans. These new plays are currently identified by only 2D seismic data. The only well drilled close to these play is Gem Reef-1 which encountered gas shows in these similar sands which pinch out onto a volcanic high. But the well was not positioned in the best location to test these sands. Hence these new plays present the new exploration opportunities. One well was drilled in the South Dent Trough but did not encounter any hydrocarbons. The main reasons are the questionable structural closure due to the poor velocity control, poorly defined trap due to poor data quality and the absence of the reservoirs. The well is located up-dip in a slope setting thus not much reservoir development is expected. The sand development should be better downdip in the basin floor fan setting. Acquisition and processing of new, high quality regional seismic data over the eastern and southern parts of the East Sabah basin were carried out in 1999 and 2004. The objective is to upgrade the prospectivity of this exploration-neglected area. Coupled with regional geological study in the East Sabah Basin, the interpretation of these newly acquired seismic data has unraveled new, untested exploration plays, which include both structural and stratigraphic plays. The deep Middle Miocene structural play with 4-way dip closures is observed within the southeastern margin of the Sandakan sub-basin. These structures were generated during the Pliocene uplift together with the creation of the onshore Dent Anticlinorium. This structural trend is expected to continue in the Dent onshore area but at shallower level. The deep Middle-Upper Miocene turbidite play, determined by seismic facies analysis and amplitude extraction, is located in the eastern portion of the South Dent Trough. The delineation of this play, expressed by the gently mounded seismic facies, can be further enhanced by 3D seismic coverage. Finally, the Middle Miocene pinnacle reef play, clearly imaged by the new seismic data as mounded facies, is present in the central area of the South Dent Trough. Covered by marine shales, the pinnacle reef poses as a valid play. The only well drilled in this area only bottomed just above the reefal buildup after encountering some limestone stringers.
-
-
-
Paleofacies Mapping of Balingian Province using 3D Megamerged Seismic Data
More LessThe Basin Assessment Group of PREX, PMU embarked on merging of eighteen 3D datasets in the Balingian Province, part of the Sarawak Basin in late 2005. The 3D datasets used are of various vintages from 1984 to 2004 covering an area approximately 11000 sq km over 27000 sq km of Balingian province. This 3D mega merged data was utilised in the interpretation and mapping project in 2008 to establish an updated regional correlation and paleofacies and identify new hydrocarbon play, leads and prospects. This mega merged data allowed visualization of the regional depositional facies in three dimensions. Previous paleofacies mapping of the Balingian Province was based mainly on drilled locations with well logs and biofacies. It does provide a broad paleofacies maps of the Balingian Province, especially for Cycle I and Cycle II megasequences. With the advent of new 3D megamerged seismic data, paleofacies mapping can then be carried out with better coverage and detail based on seismic facies analysis calibrated to the numerous wells drilled in the area and updated biofacies. Furthermore, sequence stratigraphic cross-sections can be generated in any directions. Facies change can be observed easily based on the change in seismic facies and compared with the well correlation panels. In this paper, various seismic facies representing coastal plain, coastal to shallow marine and carbonate facies are described. Five paleofacies maps have been created-Cycle I, II, III, IV and V to depict the five main megasequences in the Balingian Province. The change in depositional direction from west to east in Cycle I, and Cycle II times to generally south to north in Cycle III, IV and V times is due to a major uplift at end of Cycle II. Some differences are obvious when compared with the previous paleofacies maps and they are highlighted in this paper. Furthermore, a new west to east chronostratigraphic chart is also created to depict the changes in depositional environment more accurately including showing the areas of uplift and erosion and carbonate deposition. More importantly, new plays and leads are also identified especially the Cycle III pinnacle reefs which are yet to be tested in the Balingian Province.
-
-
-
Fractured Crystalline Basement Study: The First Field Technique Used Onshore East Coast Peninsular Malaysia
A unique field technique has been implemented in study of fractures as the major contributor to secondary porosity in crystalline basement. Crystalline basement in the Malay and Penyu basins consist of metamorphic and Pre-Tertiary igneous rocks. These rock types crop out onshore in the East Coast, Peninsular Malaysia. There are four different lithologies in this study area; granitoid, metaclastic, metavolcanic and crystalline limestone, which are devoid of primary porosity. Figure 1 shows the location of the study area. No significant outcrops are available in the Eastern Belt between Kuantan and Endau where the Quaternary coastal plain is wide. Tertiary structural events recorded from PM offshore basins were the latest tectonic deformation which caused its adjacent onshore structure to be reoriented – creation of fractures. The main focuses in this study are fracture style, trend, intensity and distribution from the four rock types. The selection of outcrops are based on their closest proximity to Malay and Penyu basins.The methods used: 1. Fracture type and density study 2. Fracture attitude and dip study The fracture type and density study involved detail measuring and counting of fractures (perpendicular to traverse line and 30° or 45° to traverse line) in the representative localities. The measurement was conducted with adequate areal coverage at each location and well distributed over the study area. Fractures are classified into four groups; wide open, open, tight (visibly open) and closed. The fracture intensity is displayed as one of fracture properties and ranked. Figure 2 shows an example of fracture density and aperture for Pulau Kerengga Besar, Pulau Redang, Terengganu. Average of 100 fracture orientation measurement were collected from each area for fracture attitude and dip study (Table 1) and plotted on Schmidt strereonett (Figure 3). The fracture connectivity is effectively shown and added up as another important element in fracture properties. All these fracture properties were classified and ranked in the order from very good to very poor categories. The most promising lithologies are very fine - fine grained metaclastics and cretaceous granite exhibit high fracture intensity, open fractures and fracture intersection.
-
-
-
Seismically Driven Reservoir Fractured Reservoir Characterization Using an Innovative Integrated Approach: Joanne Field, UK
Authors Abdel M Zellou and Jeff RossJoanne Field is located on the UKCS approximately 270 kilometres east of Aberdeen on a salt-cored four-way dip closed structure. Production comes from allochthonous chalks of the Upper Cretaceous Maastrichtian Tor Formation deposited by a series of stacked turbidite lobes originating from the northwest that cover the western and southwestern flanks of the structure. Unlike the better known chalk fields of Norway and Denmark, UK chalk accumulations suffer from a combination of generally greater depth of burial and lower overpressures resulting in significantly less matrix permeability. For this reason, fracture induced permeability enhancement is a critical determinant in separated non-commercial chalk accumulations from commercial ones. Although there have been three vertical and fifteen deviated wellbores drilled in the Joanne Field, there have been no dedicated fracture identification logs acquired in any well and oriented cores have only been acquired in four wells. This paucity of hard data on the density, orientation, and production impact of the fracture networks across the Joanne structure has necessitated the application of the Continuous Fracture Modelling (CFM) technique to predict fracture permeability distributions to aid in the construction of detailed
reservoir models for production simulation. For this study, the CFM approach combined the use of highresolution seismic attributes, well based geological information and production based data to create a neural network derived fracture model that honours all the available data and predicts areas of fracture enhancement away from well control.
-
-
-
Petroleum Systems Analysis of West Africa Deepwater from Cameroon to Angola: A Systematic Approach to Identifying Exploration Targets
A petroleum systems review of West Africa deepwater, from Cameroon to Angola, was undertaken with the view of assessing the remaining potential and to determine areas for further investigation. With the wealth of exploration/production data available internally and from the public domain, a systemic approach was taken to obtain a ‘bird’s eye view’ of the geology of the margin and its petroleum systems. The study was also a means for identifying data and knowledge gaps where future studies may be focused. A chrono-stratigraphic chart for the entire West African margin provides the framework for further analysis. The chart was compiled mainly from public domain data, detailing out the main source, reservoir and seal rock units in a tectonostratigraphic
context. Information such as hydrocarbon occurrences (fields and discoveries) and wells drilled are pasted on the chart (both in printed and digital forms) for easy viewing. In its digital form, tabulated data for fields and discoveries are provided as hyperlinks to worksheets. Petroleum systems are defined by linking the reservoirs to their respective source rocks. A total of 24 petroleum systems, both proven and hypothetical are identified in all the major basins along the margin, from north to south: Rio del Rey, Douala, Rio Muni, Gabon, Lower Congo, Kwanza, and Namibe). Each petroleum system is illustrated in folio sheets, which provide details of the petroleum systems elements: source, reservoir, migration and trapping mechanism and timing, complete with a petroleum systems events chart. Besides the proven major petroleum systems, a number of hypothetical petroleum systems have been identified, which needed further investigation and validation. The chronostratigraphic charts and petroleum systems folios are used in
conjunction with a comprehensive GIS database that was established to aid further analysis of the margin.
-
-
-
Biofacies Characterisation in the Marginal Marine Environments of the Malay Basin Using Agglutinated Foraminifera
More LessBenthic foraminifera have been widely used to interpret depositional environments within rock sequence. Due to the enclosed and paralic nature of the Malay Basin, it is difficult to define the biofacies zones based on calcareous foraminiferal assemblages alone. On the other hand, the agglutinated foraminifera are more useful in characterising different biofacies in the paralic setting such as the Malay Basin since they are well represented from marginal marine to bathyal environments (Figure 1). Three modern analogs localities were carried out for the biofacies study; Sedili Besar Estuary and its offshore areas, Klang-Langat Delta and Pahang River Delta (Figure 2). In this study, we used major agglutinated foraminiferal assemblages from selected modern environments to characterise different biofacies in the marginal marine paleoenvironments. Only the most common agglutinated foraminifera species with counts of more than ten are used for the groupings. Results of the Recent foraminiferal assemblages recorded from the modern environments are discussed here. Out of the three different localities, Sedili Besar Estuary covers the most detailed and widespread depositional facies within the marginal marine. Several biofacies zones can be differentiated based on the abundance of the main agglutinated foraminifera (Figure 3). The occurrences of agglutinated foraminiferal species such as Ammobaculites exiguus, Textularia sp and Arenoparrella mexicana can be used to differentiate the nearshore, shallow marine and brackish intertidal depositional settings. The distribution patterns of some agglutinated foraminiferal assemblages inferred from this study can also be used to imply water depth, salinity and sand distribution within the marginal marine environment. Thus, it could further improve our current understanding of different depositional environments in the Malay Basin and will lead to a more precise characterisation of the paleoenvironments.
-
-
-
The Effects of Tectonic Evolutions on the Elastic Properties of Malay Basin
Authors Uzir Alimat and Shaidin ArshadA study has been undertaken to use the edited and conditioned log data from 48 exploration wells throughout the Malay Basin. The depth trends of elastic properties (density, ρ, compressional velocity, Vp and shear velocity, Vs) together with the porosity (ø) values of “pure” sand and shale lithologies of Malay Basin have been carried out using this database (Singh and Mohamud, 2008). Their study concluded that, the high values of Vp, Vs and densities along with low porosities exist at the deeper part of the basin. This is the normal trend worldwide. However, other external elements such as tectonic events, which may have some influence on the depth trends of elastic properties, were not considered in their study. The present paper will shed some lights on what the effects of such events may have on the variation of these properties along a stratigraphic horizon that crosses different tectonic zones. Malay Basin is known to have undergone a series of structural events. Major tectonic events which took place early to mid Miocene demarcated the SE portion from the NW portion, causing it (the SE part) to undergo a thermal/tectonic subsidence phase, accompanied by basin inversion (Figure 1). Special attention has been given to the prolific I-horizon which was penetrated by 23 wells out of 48 in the database. This horizon is well represented throughout the basin and has experienced periods of both relatively quiet and intense tectonic stresses. Ultrasonic measurements of core data from the I-Horizon are being collected to compare
with the log data to check for consistency. The authors believe that the tectonic evolution and stress level imposed on all the pre-inversion stratigraphic horizons and at the reservoirs level within the I-Horizon may have some influence on the reservoir’s elastic properties. Any marked differences in depth trends from two different tectonic environments along this horizon would cause some variations in the seismic responses. This may also include variations in the AVO trend, which is one of the main predictive tools for Direct Hydrocarbon Indicator (DHI) quantitative interpretation. Acoustic impedance (AI) of sand and shale has been chosen as the fundamental parameter used as the basis in analyzing the impact of tectonic activity on rock elastic properties in the Malay Basin. The true vertical depth (Depth) vs. AI trend was plotted for all the wells by using filtered end member data and the AI behavior was observed. The AI reflects the stiffness of the lithology and normally increases with depth. The comparative plot between these two lithologies for each well is shown in Figure 2. The distribution leads to a rather distinct demarcation between the southeast region marked as Zone A to the northwest and central region, which marked as Zone B respectively (Figure 3). Comparing the combined AI trends plots for all the wells for both zones had showed a contrasting regression line between sand and shale at depth greater than 1500m (Figure 4).
-
-
-
Compensating for Gas Wipeout Effect Through Velocity Tomographic Inversion: A Case History from Malay Basin
More LessTomographic inversion has been widely employed to solve for the occurrences of gas accumulation problem in seismic imaging. In Malay Basin and offshore Malaysia, there are many imaging problem related to the so-called ‘gas wipeout” effects. The occurrence of the gas wipeout zone has creates difficulties in structural tracking and estimation of the hydrocarbon resource potential for reservoirs. We present here a case history of addresses the issue of gas wipeout effect through velocity tomographic inversion and its application prior to Pre-Stack Depth Imaging processes in the South of Malay Basin. Full azimuth hybrid tomography was used to derive the sediment velocity depth model and identify velocity changes across fault, structure and gas wipeout zone. Multiple passes of gas-flood modelling and imaging allowed accurate delineation of the anticlinal structure filled with gas. The key element of this method is the use of hybrid velocity model with control from the geological structures and well velocities.
The workflow of the hybrid 3D tomography involves automatically performs the focusing analysis on the depth-imaged gathers and updates velocity models through a global inversion process. Focusing parameters were measured and projected along the computed ray paths from the imaged subsurface reflectors back to the surface. The new velocity updates are derived from this inversion process will be used to improve the focusing of the seismic gather and generating new traveltimes for each of the reflectors in the next iteration of Pre-Stack Depth Imaging with the updated model. After 3 or 4 iterations of the tomographic velocity updates, the velocity depth model was ready and sufficient to image the structures and gas effect in the area. The final velocity model derived from the PSDM process is a geological product that can be used to identify lithology changes, overpressure zones and importantly, changes due to the fluid content of the reservoirs. The result of the study shows that the final velocity model has given significant improvement in the imaging and interpretation of the structures within the gas wipeout area. The issue has been compensated in producing a structural image, producing image-gathers, propagating the wavefield throughout the domain and determining the velocity via migration algorithms and tomographic inversion.
-
-
-
Facies and Bedding Styles in Basin-Floor Fan Deposits of the West Crocker Formation, West Sabah: Implications for Deepwater Reservoir Facies Distribution
The Oligo-Miocene West Crocker Formation in the Kota Kinabalu area, West Sabah, is often described as a sand-rich turbidite system. A field programme was undertaken to study the sedimentary facies of the West Crocker as a possible analogue for the deepwater reservoirs of the NW Sabah Basin and elsewhere. The formation consists predominantly of thick-bedded sandstone facies (beds are commonly >1 m thick) deposited by high-density turbidites. In places, there are the “classical” flysch-like, thin-bedded turbidite sequences deposited on the basin floor. In the thick-bedded successions, sandstone beds are commonly 1.5-3 m thick, while ‘megabeds’ may reach anomalous thicknesses of up to 35 m. The presence of amalgamation surfaces within some of the megabeds suggests that they were produced by multiple flow events. Despite the abundance of thick sandstone beds, there is a general lack of large-scale channelized scours, even at the bases of the megabeds. Almost all the sandstone beds have tabular or sheet geometries. Evidence of channel-fill deposits is found only in the innermost (eastern) part of the system. This suggests that the West Crocker Formation, at least in the vicinity of Kota Kinabalu, represents the non-channelized deposits of a basin-floor fan. The internal architecture of basin-floor fan succession are governed by the vertical (and possibly lateral) distribution of the three dominant facies types. Each facies type is the product of gravity flow events, identified in outcrop as turbidite, debrite and slump. Turbidite beds are dominated by massive to poorly laminated sandstone (Bouma Ta/Tb divisions), which are relatively mud-poor and normally graded with common dewatering features. The beds fine upward into parallel and ripple laminated heterolithics (Tc/Td), which are sometimes burrowed. More commonly, the massive beds have ‘floating’ shale clasts near or at the top, indicating deposition by high-density turbidity currents. Debrite beds generally consist of internally chaotic mud-rich units with scattered shale/mud clasts. They generally have sharp bases and directly overlie the massive sandstone beds, often filling hollows or subtle topographic lows at the top of the massive sands. Debrite beds, of varying thicknesses, tend to overlie turbidite beds with sharp, and often irregular, contacts. A third facies type is slump, which comprise generally muddy or shaly intervals displaying pervasive softsediment deformation (folding and faulting) and remobilization of pre-existing deposits. All three facies types
are intercalated with thin ‘distal’ turbidite (Bouma Tc/Td) and hemipelagic shale intervals. Reservoir architecture and, consequently, heterogeneity of basin-floor fan succession, are ultimately governed by the distribution of these different facies types. Predictive depositional models for these facies types are important for effective reservoir characterization. We observe that the sand-rich West Crocker outcrops around Kota Kinabalu span a distance of 40 km along strike of the Kinabalu coastal plain, and we interpret them as representing the medial part of a basinfloor fan system, which is dominated by the thick-bedded sheet sandstones. Although there may be stratigraphic repetition in this steeply dipping succession, due to the thrust-related deformation, it is estimated
that the outcrops represent a minimum total thickness of 5000 m of stacked mid-fan section. Since there is evidence for major channelization only in the most “updip” (eastern) outcrop, we speculate that the upper/proximal to base-of-slope part of the West Crocker system must occur east of our studied outcrops. By the same token, the lower/distal parts of the system must lie to the west beneath the coastal areas and beyond, and may possibly crop out on the islands off Kota Kinabalu and Klias peninsula.
Hence, the West Crocker Formation is indeed sand-rich (estimated net-to-gross ratio > 70-80%) only insofar as the outcrops around Kota Kinabalu represent the exposed medial fan lobes, and are not necessarily representative of the entire West Crocker depositional system. Further characterization of both updip and downdip sections relative to the more exposed and accessible medial fan belt is required for a more complete understanding of the West Crocker depositional system.
-
-
-
Sequence Boundary Recognition Criteria in Central Luconia Carbonate Cores
More LessNumerous third to sixth order sequence boundaries were recognized in selected cores from two Central Luconia carbonate buildups. Criteria to recognize a sequence boundary in these cores can be broadly grouped into three categories: (1) the nature of the surface itself, (2) features below the surface, and (3) features above or across the surface. The nature of the surface itself refers to whether the surface is subtle or sharp, apparently planar or irregular/erosive (Fig. 1), and with or without burrows, borings or encrustation. Features below the surface can be subdivided into macroscopic and microscopic features indicative of subaerial exposure and associated meteoric diagenesis and/or karst processes. The macroscopic features include (i) secondary pores such as
moulds, vugs, fractures and fissures, (ii) relict root systems e.g., carbonized rootlets and open or cemented root tubules, (iii) alteration features e.g., breccias with weathered, crumbly and/or chalky appearance or tight texture with brown mottling and/or pinkish colouration, and (iv) karst cavities or cave openings either cemented by speleothems (occasionally multi-phased) and/or filled with mudstone, dolomudstone, sediments or paleosols (Figs. 2 and 3). The microscopic features include (i) moulds and vugs which either still remain open or have been cemented, (ii) pendants or meniscus cements, (iii) bladed and/or equant calcite spar cements, and (iv) vadose silt geopetally filling secondary pores. Features across or above the surface include (i) presence of clasts of underlying rocks or rocks altered by meteoric diagenesis, and (ii) major change in depositional facies, parasequence set stacking pattern and/or microfossil assemblage. In general, the presence of a combination of the above-mentioned features characterizes individual sequence boundaries, and more severe diagenetic alterations or better developed karst features are observed below lower order sequence boundaries.
-
-
-
Biofacies Assemblages of The Klang-Langat Delta, Selangor, Malaysia
More LessThe Klang-Langat delta is located on the west coast of Peninsula Malaysia, about 80 km from the capital city, Kuala Lumpur (Fig. 1). It is classified as a tide-dominated delta, having a tidal range of up to 4m (Coleman, 1970). This area is selected as one of the analogues for modern delta study because of its distinctive geological setting, accessibility, and the demarcation of the mangrove as a forest reserve. Being highly influenced by tide, the area provides a good analogue for assessing modern biofacies assemblages in the tidal dominated delta system. This paper present the results of foraminifera and palynological analyses on 181 bottom surface sediment and shallow core samples taken from selected transects in the shallow offshore and the lower reach
of Sungai Langat. The samples were collected during four field work programs conducted from April to December 2007. In the field, observations on the composition of vegetation along the rivers were noted (Fig. 2). Other field data measured include water depth, pH, salinity, and turbidity. The data of foraminiferal and palynological analyses were interpreted based on their distribution pattern, abundance and species diversities (Figs. 3 -5). The results were also evaluated by incorporating sediment grain size and other ecological parameters (Table 1). Six biofacies assemblages have been recognized. The biofacies assemblages are freshwater, upper brackish intertidal, lower brackish intertidal, channel banks, tidal channel and tidal flat/delta front.
-
-
-
Application of High-Resolution Biofacies for Better Depositional Environment Interpretation in the Malay Basin Tertiary Sedimentary Successions
Interpreting detailed environment of deposition (EOD) as accurate as possible for the delineation of reservoir geometry and continuity is crucial in any field development plan, especially in reservoir geological modeling. Conventionally, a conceptual depositional model is developed from the sedimentological study of cored sections and constrained by wireline logs and seismic signatures. If available, any results from routine biostratigraphic analysis will be incorporated to provide additional constraints for the interpretation of EOD. In the Malay Basin, although biostratigraphic analysis is routinely undertaken on most wells, biofacies and sedimentological interpretations are often in conflict, and thus give contradictory results regarding to environment of deposition and salinities. For example, a peculiar anomaly observed in several cored sections shows that in numerous instances, upsection change to shallower water as suggested from sedimentological criteria coincides with increased in salinities based on microfauna/flora. In another observation, coal layers that were interpreted as brackish water coals from sedimentological study can be shown to be autochthonous freshwater coals when analysed using high-resolution biofacies. Our approach to high-resolution reservoir-scale biofacies analysis will be discussed in detail. For reservoir-scale interpretation using bed-to-bed biofacies analysis, biofacies signals are obtained through a carefully designed high-resolution systematic sampling program. Samples are selected from each lithofacies encountered in cored sections and analysed in a manner sufficient to display the temporal succession of biosignals. For each lithofacies, a minimum of three samples were taken to represent lower, middle and upper units, while lithofacies showing a continuous succession were sampled at regular interval. With respect to coals, samples were taken at a much closer interval as to ensure sufficient representative of biosignals are captured. As a result, the overall sample density may become greatly increased, sometimes with samples analysed at 1cm intervals, but more typically a sample every 50 – 100 cm. Since the results answer fundamental sedimentological questions, the work is easily justified. Using this approach, temporal biofacies successions are better understood, and interpretation of EOD is greatly improved to a higher degree of confidence than is possible using sedimentology alone. Also, shales associated with allocyclic and autocyclic sedimentary controls can be readily differentiated, allowing the sedimentary succession to be placed in a realistic sequence stratigraphic perspective. Examples of selected cored intervals from different stratigraphic units in the Malay Basin are discussed.
-
-
-
Hydrocarbon Generating Potential of Terrigenous Shales and Coals of the West Balingian Province, Offshore Sarawak
Authors Awang Sapawi Awang Jamil and Abdul Jalil MuhamadThe Balingian Province is a proven hydrocarbon province in Sarawak and has been actively explored since the early 1920s. The Balingian Province is subdivided into West and East Balingian sub-provinces which are separated by N-S alignment of sub-basins or depocentres, namely the Acis, South Acis and Balingian sub-basins (Mazlan and Abolins, 1999). The sediments had been subdivided into 8 sedimentary units, called cycles, I - VIII, with Cycle I as the oldest (Ho, 1978). Major oil and gas accumulations are found in the western part of the province, whereas only minor accumulations occur in the eastern part. Geochemical characteristics of most oils indicate generation from mature source rocks containing high proportion of terrigenous organic materials (e.g. Awang-Jamil et al., 1991). Despite active exploration, uncertainty still surrounds the identity of the source rocks responsible for generating the oil and gas. Therefore, in this study, detailed geochemical investigation of the source-rocks of the West Balingian
Province was carried out. The objectives of this study were to determine their hydrocarbon source potential and to delineate the oil generation threshold through assessment of maturity. For this purpose, 90 rock samples (ditch cuttings and cores) from three wells (DA-2, DB-2 and DE-1) drilled in the northwest area of the Balingian Province was subjected to a series of organic geochemical analyses. The two main lithologies analysed were shale and coal, selected from thermally immature to mature sections of Cycles I, II and III of the Tertiary sediments. Rock samples from Cycles IV - VIII were not included because they are generally immature (below 0.4% Ro) and therefore are not thought to have contributed to hydrocarbons accumulation in this area.
-
-
-
Regularised 1D Inversion of Marine Controlled-Source Electromagnetic Data
More LessWe present an algorithm developed for layered-earth inversion of data acquired using an inline horizontal electric dipole (HED) marine CSEM survey method. The inverse problem is solved using the Tikhonov derivative-regularization and the singular value decomposition method. The iterative scheme starts with a half-space resistivity model and finds the smoothest model that fits the data to 1 rms error. The inversion takes into account data errors, any available a priori information about subsurface structure, nonlinearity of the forward problem, and solution non-uniqueness thus providing a reliable constrained inversion model . Application to synthetic data is presented and a field example is discussed.
-
-
-
Comparative Evaluation of Frequency and Time Domain Csem Methods for Malaysian Offshore Environments
We have undertaken an evaluation study of the capability of both frequency-domain and step-on time-domain CSEM methods for reservoir detection in both shallow-water and deepwater environments of Sarawak and Sabah in Malaysia. We selected some well sites for this evaluation study. The shallowwater well site (79 m water depth) consists of a 200 m thick reservoir of resistivity 100-200 ohm-m (Ωm) and the background resistivity is 2-5 Ωm. For the deepwater case (1137 m water depth), the well site consists of a 70 m thick reservoir of resistivity 100-200 ohm-m (Ωm) and the background resistivity is 2 Ωm. For modelling purposes, we constructed 4-layer models for each site. We used three frequencies (0.25, 0.5, 0.75Hz) for the frequencydomain method and a transient time window of 250s for the stepon time-domain modelling. The forward modelling studies show that both methods can potentially discriminate between the reservoir and non-reservoir anomalies in 79 m water depth when the resistivity contrast is greater than 20:1. In the deepwater case, the fCSEM and tCSEM methods show similar response patterns.
-
-
-
Imaging Stratigraphic Channeling with Seismic Attributes in the Malay Basin
In Seismic interpretation a reflection is generally characterized by its arrival time (T) or (F), its reflection strength or amplitude (A) and by its phase. All other attributes are simply linear combination of these three. Each of these attributes represents different aspect of a seismic reflection where in turn brings out different aspects of the geologic features. Amplitude characterizes the reflection strength and can be used in finding sweet spot. A strong amplitude bright spot may be a Direct Hydrocarbon Indicator (DHI) if it is structurally confirmable. An amplitude shutoff may be an indicator of a hydrocarbon water contact. Frequency on the other hand signifies resolution to detect thin beds or an attenuation effect indicative of gas. Phase is the most sensitive of all the attributes and is primarily an indicator of structural discontinuities like faults, unconformity or pinch outs and other geomorphological features.
-
-
-
3-D Tomographic Q Inversion for Compensating Attenuation Anomalies
Authors Kefeng Xin and Barry HungFollowing our previous work on Amplitude Tomography that deals with amplitudes alone, we extend our effort to include the compensation of bandwidth and phase of seismic signals that are distorted by seismic attenuation. Our new approach involves utilizing tomographic inversion for estimating the quality factor (Q) from prestack depth migrated common image gathers. By filtering the seismic data into different frequency bands and measuring the effect of attenuation on amplitudes in each band, the frequency dependent effect, which was ignored in our previous work, of attenuation is fully taken into account, allowing Q to be estimated from our tomographic method. By using the estimated Q volume in one of the migration methods that incorporates Q in the traveltime computation, we demonstrate, through examples, that our workflow provides an optimal compensation solution that resolves amplitude and bandwidth distortions due to seismic attenuation.
-
-
-
Real Time Depth Determination for Drilling Using Seismic While Drilling Checkshots
By Aqil AhmedReal-Time Checkshots on a 3 Well / 3 Block Exploration Campaign help to accurately determine depth of key Formation marker offshore East Asia
CHALLENGE
An offshore 3 block / 3 well exploration campaign needed to determine the depth of a key formation marker as early as possible to reduce risk and save time. This meant acquiring good checkshots even inside casing on a vertical well. The target also had a possible pressure ramp associated with it.
SOLUTION
By acquiring checkshots while drilling using the seismicVISION* tool ,a real time update of the timedepth relationship was acquired thus the depth of the target was known accurately ahead of time and key drilling decisions made accordingly.
REDUCING UNCERTAINTY
An Operator in East Asia ran the seismicVISION* service to determine the depth of a key formation marker on 3 separate Exploration Blocks that were being evaluated. With an initial depth uncertainty of +/- 100m from the surface seismic, the client wanted to reduce this to less than 20m as early as possible so that casing could be set safely and accurately in a formation that had possible pressure ramp and well stability issues with possible pack-offs if the hole remained open for too long. Additionally as 2 of the 3 wells were in a Deep Water environment the need to make accurate real time drilling decisions was even more imperative. seismicVISION* - SVWD The seismicVISION* service acquires checkshots while drilling whilst taking up minimal rig time. Windowed Real Time Waveforms are transmitted uphole from the LWD seismic tool using mud pulse telemetry after acquiring the seismic station at connection, an acoustically quiet period. The source is a standard 3 air gun cluster at surface deployed from the rig. The checkshots are then processed from the waveform at the wellsite and real time depth updates calculated whilst drilling.
PRE-JOB PLANNING & OPERATIONS
Detailed pre-job modeling between Operator and SLB, and checkshot acquisition close to the target, enabled highly accurate updated depth prediction using Real Time answers products at the wellsite after checkshot processing.
RESULTS
For all 3 vertical Exploration wells in 3 different blocks, the target depth was predicted to within 10m each time allowing safe and successful drilling with casing being set at the correct point. These depths were confirmed by subsequent Wireline logging runs.
Well TD’s were set during drilling on the basis of the hydrocarbon sand depth prediction.
CONCLUSION
By employing seismic while drilling technology, the Operator was able to establish accurately, the depth of a key formation marker during drilling, hence reducing risk and uncertainty on exploration wells leading to a successful exploration campaign.
-
-
-
Addressing Petrophysical Issues in a Low Resistivity Pay Environment with Modern Spectroscopy Logs and Nmr
Low Resistivity and Low Contrast (LRLC) Pay environments present significant problems for accurate petrophysical evaluation. The subject of this paper is a typical SE Asia LRLC reservoir with variable resistivity values in the pay zone which can sometimes be lower than those in the water zones. Low resistivity values are generally due to variable clay content. Variable clay content in the reservoir affects both the neutron and density logs to such an extent that using a basic logging suite porosity evaluation, fluid
identification and reservoir quality assessment are adversely affected, particularly for operational decision making. Clay conductivity effects in conjunction with low salinity formation water mean that resistivity-based saturations are frequently pessimistic and are heavily dependent on estimates of clay content. All of the basic petrophysical outputs are therefore compromised in some way in these environments. The addition of modern Spectroscopy logs on two recent wells has shown that some of these evaluation problems can be overcome by using elemental abundances derived from spectroscopy to define the response of the neutron and density logs to the rock matrix. Current generation Spectroscopy logs measure several major rock forming elements which impact the bulk properties of the rock such as grain density. After matrix correction on the basic logs, porosity values can be better computed and hydrocarbon identification is improved. Clay content predicted from the elemental Spectroscopy logs appears to show more consistency than predictions from other Vclay estimators- all of which have specific weaknesses. The presence of NMR in the logging suite addresses deficiencies in the assessment of reservoir quality and saturation through direct measurement of irreducible water and indirect correlations to permeability-shown to be reliable in the subject reservoir. The combination of NMR and spectroscopy corrected density porosity gives potentially the best estimate of porosity. The combination of Spectroscopy and NMR logs with the basic logging suite significantly enhances petrophysical evaluation capabilities in any environment where clay content and distribution is variable and difficult to estimate.
-
-
-
Velocity Modeling in Gas Sagging Area
Authors Sia Chee Chuan and Munji Syarif and Achmad NurhonoVelocity model provides direct linkage between time domain and depth domain. Time to depth conversion of interpreted surfaces, faults and seismic data is an important part in the 3D geological modeling for volumetric assessment. The data used for velocity modeling may include seismic velocity data, well velocities (from checkshot, VSP, and/or synthetic seismograms), well markers, and surfaces. Conventionally geophysicist uses checkshot data, stacking velocity, or checkshot integrated with stacking velocity directly. These methods are widely used for depth conversion in a normal area (i.e. without gas sag or pull-up effect in surface seismic interpretation). In this project, the existence of shallow gas cloud in the area of study is causing sag effect instead of
anticlinal structure on the seismic data. The common solution for the gas sag is manually interpreting the anticline at the affected area. However, manual seismic horizons interpretation to correct the sag to anticline is not applicable for this project as seismic inversion work is involved. The manual correction in seismic horizons interpretation will introduce an artifact in the seismic inversion process. Thus the seismic horizons interpretation has to honor the sag effect. The depth conversion from the conventional
velocity modeling method above would not able to solve the gas sag effect, where the sag exists instead of anticline in the depth domain. A simple but effective workflow is introduced to overcome the problem where the seismic velocity was corrected first, and then calibrated with the well velocity. Considering a point - ‘X’, which is unaffected by shallow gas beside the gas sag is chosen as reference for time and velocity (TWT difference factor derivation and seismic velocity correction). A TWT difference factor is derived between the point ‘X’ and gas sag. Then the seismic velocity is corrected with the TWT difference factor, thus remove unreliable velocity within the gas sag area. This corrected seismic velocity is then calibrated with well velocity and the latter result is used as an input for velocity modeling. The structural dip of depth converted structure surfaces are QCed with average dip from the OBMI to ensure no anomaly on dip changes. The residual depth of the velocity model is within 10m.
-
-
-
The Occurrence and Structural Characteristics of “Brick-Structure” Coal Fractures (Cleats) in Mukah-Balingian, Sarawak, Malaysia: a Probable Fault Reactivation Feature
Authors Wan Hasiah Abdullah and Sia Say Gee and Wong Yien LimThe Tertiary sequence of Northwest Borneo was gently folded with NNW- to SSE-trending axes during the Middle Miocene and the subsequent folding and uplift during the Pliocone-Pleistocene affected all the older stratigraphic successions (Haile, 1969). In this current study, a NNW- trending “coal-brick structure” (Figure 1) has been identified and is postulated to be related to the Pliocene-Pleistocene reactivation of preexisting structural fabrics. This interpretation is based on a number of supporting structural features which include the similar NW-trending fault bounded graben and horsts in the onshore Mukah area and the adjacent offshore area (Mazlan Madon, 1999). The “coal-brick structure” occurs at two locations; in the northern part it occurs in the Upper Miocene
Balingian Formation close to the contact with the Lower Pliocene Bergih Formation, while in the south it occurs in the Upper Pliocene Liang Formation close to the contact with the Eocene Belaga Formation (Figure 2). A few faults have been mapped close to the brick structure. Based on the similar orientation of the NWtrending of the long fractures (face cleats) of the “coal-brick structure” to the fault at the northern area, as well as being similar to the NW-trending adjacent offshore regional structural trend, it is postulated that the occurrence of the “coal-brick structure” is an indication of a fault-bounded zone associated with folding, uplift or unloading of the overburden, and could indicate proximity to an unconformity. It is observed that there is a variable cleat strike postulated to be within the main faulting region close to a hinge of the fold, while further away from the hinge the “brick structures” are larger in size and display a prominent long fracture pattern parallel to the NW-trending regional structural trend including the offshore West Balingian bounding fault line. It is postulated that the folding and faulting and the associated “coal-brick structure” in the Balingian and Liang formations point to possible structural reactivation of the Early-Middle Miocene regional faults and structural fabric within the Mukah- Balingan and adjacent offshore areas. Similar fracture patterns that are parallel to pre-existing regional faults has also been observed in basalt of Quaternary age at Pantai Batu Hitam, Pahang which has been postulated to point to the possibility of reactivation of regional Pre-Tertiary faults in the Malay Basin region (Tjia, 2008). The Pliocene formations (Begrih and Liang) rest directly on the Eocene Belaga Formation. Such major unconformities are common in onshore and offshore Sarawak. In the offshore area adjacent to the Mukah-Balingian region, an angular unconformity that rests directly on the Oligocene-Early Miocene (Cycle I-Cycle II) occurs at the base of Cycle VI/VII in Balingian Province (Mazlan Madon and Abolins, 1999). In
the adjacent Tatau Province, Cycle III/IV of Early–Middle Miocene strata were reported by Mazlan Madon and Redzuan Abu Hassan (1999) to rest directly on the Paleocene-Eocene basement (equivalent to onshore Belaga Formation). The shallow depth or immediate overlying proximity of the Pliocene Liang to the Eocene Belaga Formation may facilitate the Liang inheriting the Belaga fault directions and associated structural fabric upon reactivation. An important implication of the development of these cleats is their potential to act as conduits for hydrocarbons such as for coalbed methane gas.
-
-
-
A Comparative Source Rock Study of Two Proven Petroleum Systems: The Marine Madbi Formation of Yemen and the Terrestrial Nyalau Formation of Sarawak, Malaysia
More LessTwo contrasting petroleum systems have been evaluated and compared. Marine shales of the Jurassic Madbi Formation in the Masila basin, Yemen (Fig.1a) and Tertiary coals and organic-rich sediments of the Nyalau Formation (offshore stratigraphic equivalent to the Cycle I & II of Balingian Province,) in Sarawak, Malaysia (Fig.1b) have been subjected to detailed organic petrological and organic geochemical studies. An assessment, based on organic facies characteristics, has been carried out on these sediments, in order to distinguish, characterise and evaluate source rocks deposited in marine versus paralic depositional sitting. The methods employed include evaluation of organic carbon content (TOC), biomarker distributions, pyrolysis-gas chromatography analysis and petrographic data. The maturity assessment of the samples analysed is mainly based on vitrinite reflectance (%Ro). The organic geochemical and organic petrological approach here has been able to clearly differentiate between marine and terrestrial depositional setting. Organic facies parameters such as Tm/Ts, Pr/Ph, Pristane/n-C17, Phytane/n- C18 and oleanane/C30 hopane ratios appear to reflect variation in depositional conditions and/or source input. Although there is a mixture of land-derived and
marine-derived organic matter in both sediments, the depositional conditions of these formations can be distinguished based on these organic facies parameters, whereby the Madbi shale samples were deposited in a reducing suboxic marine condition while the terrestrial Nyalau sediments in suboxic to oxic paralic condition of deposition (Fig.2) The Madbi shale samples possess vitrinite reflectance (% Ro) values ranging from 0.74-0.88% thus indicating an early mature to peak mature range, while the Nyalau sediments possess vitrinite reflectance values of 0.50-0.66% which suggest the samples are early mature for oil generation. The level of thermal maturity attained by these samples is also reflected in their biomarker distributions as indicated by the approximate 60/40 ratio of the S to R isomerisation of the C31 and C32 hopanes (Fig.3). With regard to oil generation potential, good source rock potential is suggested by the high TOC values for Madbi shales and the organicrich sediments of the Nyalau Formation, as well as owing to their liptinite-rich nature (based on petrographic data) (Fig.4) and Py-GC dominated by n-alkane/alkene doublets (Fig.5). Within early to peak oil window maturity, the Madbi shale would be expected to be a better source rock for oil as indicated from its higher abundance of Type I and II kerogen compared to the Nyalau Formation which are dominated by Type II and III kerogen. Based on this study, good oil/gas generating potential is anticipated from the coals and carbargillite/coaly shales of the Nyalau Formation, owing to predominant n-alkane/alkene doublets and aromatic compounds (Fig.5).
-
-
-
Coastal Facies Sand Composition and Beach Dynamics on Pulau Pangkor to Assess the Impact of Potential Oil Spills
More LessThis research is conducted in Pulau Pangkor to assess the impact of potential oil spills by studying the coastal facies sand composition and beach dynamics of the island. This study includes mapping coastal facies with remote sensing, field sampling and analyzing the sand composition.
-
-
-
3D General Surface Multiple Prediction on Full Azimuth Coil Shooting Survey
Authors Andreas T. Waluyo and Steven Wiseman and Dmitry NikolenkoOffshore Kalimantan, Indonesia in the Tarakan Basin, seismic illumination has been a problem for interpreters for many years due to its complex geology. During the summer months of 2008 a full azimuth Coil Shooting survey of approximately 536 sqkm was conducted over the Tulip field. Unlike conventional race-track acquisition, in which the vessel traverses a straight line, with Coil Shooting the vessel traverses a circular pre-plot. This geometry fully sampled the full azimuth range to overcome a number of geological issues which resulted in very poor target imaging. With acquiring a true full azimuth survey benefits signal sampling it also acquires a multiple dataset fully sampled in azimuth. Due to the water-bottom shape and reflectivity complexity of the field, the resulting seismic data contained strong and complex surface-related multiples that conceal the underlying primary seismic energy. Due to the crossline rugosity of the water-bottom the downward Reflection Points (DRP) of the multiple travel paths are not in line with the source and receiver points creating 3D multiple effects. It is well known that the effect of azimuth errors on multiples is greater then on primary events. In theory, conventional 3D Surface Related Multiple Elimination (3D SRME) can provide an accurate solution to these types of multiples. However for Coil processing, conventional 3D SRME as typically implemented will not produce an accurate multiple prediction model. Without an effective de-multiple process, the resulting image from data processing can provide limited information. Recently WesternGeco introduced 3D General Surface Multiple Prediction (3D GSMP*) as a solution to attenuation of multiples in this type of environment. 3D GSMP is a practical approach to 3D SRME that can handle the irregularities in real life survey geometries and provide a superior multiple model prediction. It takes care of 3D effects and works in true azimuth. Without 3D GSMP, strong residual multiples obscure the seismic image of Tulip Coil data, making any kind of seismic interpretation extremely difficult. 3D GSMP produced a final image with minimal or no residual multiples. This paper will illustrate the successful use of this approach.
-
-
-
Preliminary Assessment of the Coalbed Methane Potential of the Mukahbalingian Coal Field, Sarawak
Authors Sia Say Gee and Wan Hasiah AbdullahWorldwide increase in coalbed methane development began in approximately 1988, prior to this coalbed methane was considered a safety hazard and was intentionally vented to the atmosphere to prevent mine gas explosions. In 2007, the United States has produced more than 50 billion cubic meter of pipeline quality coalbed methane (EIA, 2007). To date no effort has been made to explore the coalbed methane potential in the Malaysia’s coal basins. Early coalbed methane exploration targeted thermally mature high rank coals, but the study carried out by Bustin and Clarkson (1998) on a series of Australian, Canadian and United States coals have indicated that there is no or little correlation between coal rank and methane adsorption capacity as commonly assumed.
With the successful development of coalbed methane in the Powder River Basin, San Juan Basin and the Greater Green River Basin of the United State of America (SanFilipo, 2000, Nuccio, 2001, Breland, 2004), low rank coals have also become exploration target. Basically, at the current state of knowledge on coalbed methane, the study of coalbed methane is an empirical process (SanFilipo, 2000). Coalbed methane is believed to be generated during three distinct stages of the parent coal's maturation history: Stage 1, early biogenic gas due to bacterial activity during the conversion of peat to coal, Stage 2, thermogenic gas due to volatilization of coals constituents as rank increases, and Stage 3, late biogenic gas due to bacterial activity after the coal has been
uplifted to near surface (Rice, 1993). The Mukah-Balingian Coal Field consists of Mukah Coal Basin hosting the Miocene Balingian Formation and Balingian Coal Basin hosting the Pliocene Liang Formation (figure 1). These coals are of low rank whereby the vitrinite reflectance of the exposed Mukah- Balingian coal ranges from 0.34%-0.54% (Chai and Wan Hasiah, 2004) indicating the Mukah-Balingian coals are at the early thermogenic methane generation stage (figure 2), which usually unable to generate enough
methane for development. However, the possibility of the coals also accumulating migrated thermogenic and late biogenic methane, which will enhance the development potential of the methane, especially for the Mukah Coal Basin, cannot be discarded. The deeper coals at Mukah Coal Basin may have already reached the peak of wet gas generation (Mazlan and Abolins, 1999), where the thermogenic methane generated has migrated up along the coal seams or faults, together with the late biogenic methane produced at near surface by the bacterial activity after the coal has been uplifted could have enhanced the coalbed methane development potential of the coal basin. The distribution and orientation of cleats in coal will serve as permeability pathways for migration and accumulation of thermogenic methane generated during coalification. Coal seams at Mukah-Balingian Coal Field have a well-developed cleats network (figure 3); with the face cleats trending NNW to NNE and the butt cleats approximately perpendicular to it. The coal resources of the Mukah and Balingian Coal Basins have been estimated to be of 550 million tonnes (Sia and Dorani, 2000) and 200 million tonnes (Hussein and Dorani, 2000) respectively. At a pessimistic gas storage capacity of 2 m3/tonne and an optimistic gas storage capacity of 10 m3/tonne, as of the biogenic gas in Soma lignites, Turkey (Inan, 2008), have translated the coalbed methane in place from 1,100 million m3 to 5,500 million m3 for the Mukah Coal Basin and from 400 million m3 to 2,000 million m3 for the Balingian Coal Basin, respectively.
-
-
-
Variation in Biomarker Distributions for a Lower Coastal Plain Source Rock Sequence in the Malay Basin
In this study, an attempt is made to integrate biomarker parameters with biofacies interpretations determined from palynomorph and foraminifera assemblages, sedimentological features and bulk geochemical properties. This is to investigate the biomarker signatures for various depositional environments. For this purpose, a well preserved 100-meter cored section from the Tangga Barat-3 well drilled in the Malay Basin was selected. This section transects lower coastal plain depositional environments within the Late Middle Miocene. Vitrinite reflectance measurements ranging from 0.4 – 0.5% indicate that the source rock intervals are immature for hydrocarbon generation. The immaturity of these sequences makes identification of biomarkers more challenging.
-
-
-
Integrated Approach to Maximizing Asset Value in the Mature Palas Field, Malaysia
The Palas field, located offshore Peninsula Malaysia, was discovered in 1977 and has been producing for over 20 years. The field was developed in two stages with an initial drilling program in 1985 focused on Lower Miocene Major I reservoirs with Minor I reservoirs as secondary targets, and a subsequent drilling program in 2000 focused on Group J reservoirs. With maturing production from the Major I and Group J reservoirs there has been a shift in focus towards the less depleted Minor I reservoirs. This paper describes the evolution of Minor I reservoir drilling targets, from secondary objectives with opportunistic completions, to key targets in a recent infill drilling campaign. The Lower Miocene Minor I reservoirs are comprised of tidally influenced, lower delta plain
sandstones and occur as discrete channels to amalgamated channel complexes. Reservoir compartments are separated by intervening shales resulting in multiple fluid contacts and oil columns ranging from 15 to 70 meters. Seismic imaging is challenged by the relatively thin nature (5 – 10m gross thickness) of the sandstones and numerous interbedded coals. Reservoir-scale mapping is primarily based on well data. Opportunity generation was guided by mixed but encouraging production performance from the
sparse oil completions taken in the Minor I reservoirs and included collaborative Geoscience and Reservoir Engineering construction of 3D geologic and reservoir simulation models to high-grade infill drilling opportunities. This effort resulted in several proposed development wells in the Minor I reservoirs, two of which were drilled as part of a recent infill program. Encouraging results from these two wells are being used to further the understanding of the Minor I reservoirs and mature additional infill opportunities.
-