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PGCE 2010
- Conference date: 29 Mar 2010 - 30 Mar 2010
- Location: Kuala Lumpur, Malaysia
- Published: 29 March 2010
21 - 40 of 100 results
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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