PGCE 2010

The 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

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.

The 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.

In 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.

Gravity 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.

Data 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.

Open 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.

The 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.

The 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.