Malay Basin Research Articles

Fracture characterization in basement reservoirs through seismic attributes

R ecent efforts to understand fracture characterization, their density and numbers have increased signifi­cantly. With the introduction of novel technologies and methodologies of data preconditioning, decom­position, and attribute analyses, new workflows have been introduced to optimally determine and visualize effective fractured networks. In detailed seismic data analysis it is critical to determine the accurate location of effective fracture zones and their characterization as these may lead to high potential hydro­carbon exploration zones. Therefore we suggest a workflow to delineate and quantify effective fracture networks from seismic data. Our proposed methodology has been calibrated using all available surface and subsurface data that included testing results. The three core elements to this workflow are: fault network delineation, fracture density zones estimation, and effective fracture zones identification. These are then used to visualize the most potential regions in the area. Then through 3D volumetric representation of the blending results, one can quantify the amount of effective fractures per region and identify areas of interest. For a detailed description of the methodologies and workflows used to achieve the results, the reader is referred to (Aqrawi and Aqrawi, 2013) and (Alai et al., 2014). Here we showcase a sequential and systematic approach to delineate dense effec­tive fracture zones from seismic data. Only the seismic data is used to perform this analysis, and the well data is solely used for correlation and validation. The paper discusses the integration of the sequential steps of the proposed methodol­ogy that incorporate ‘consistent’ unsteered fault networks, detailed estimation of the fracture density and effective fractures zones and the geologic and structural setting of the studied area. Three datasets were obtained from the Malay basin, which has been formed as a pull-apart related to the development of the three pagoda right lateral fault. Open fractures within the Malay basin that originated by strike– slip tectonics strike NE-SW and ESE-WNW and oblique to major bounding faults of the studied areas. Wells drilled with trajectories parallel to the bounding faults intersected higher numbers of effective synthetic fracture networks with higher testing rates. From the first dataset, numerous well data have been integrated to validate the workflows and our results are supported by well testing data. Regarding the second and third case studies, the trajectories of the planned exploration wells have been validated. In addition, our results identify potential nearby areas where appraisal wells are recommended to test additional well-developed fracture networks.

Structural evolution of Malay Basin, its link to Sunda Block tectonics

The Malay Basin is located offshore West Malaysia in the South China Sea, within north central region of 1st order Sunda Block. The basin developed partly as a result of tectonic collisions and strike-slip shear of the Southeast Asia continental slabs, as the Indian Plate collided into Eurasia, and subsequent extrusion of lithospheric blocks towards Indochina. The Sunda Block epicontinental earliest rift margins were manifested by the Palaeogene W–E rift valleys, which formed during NW–SE sinistral shear of the region. Later Eocene NW–SE dextral shear of (2nd order) Indochina Block against East Malaya Block rifted open a 3rd order Malay Basin. Developed within it is a series of 4th order N–S en-echelon ridges and grabens. The grabens and some ridges, sequentially, host W–E trending 5th order folds of later compressional episodes. The Malay Basin Ridge and Graben Model explains the multi-phased structural deformation which started with, the a) Pre-Rift Palaeo/Mesozoic crystalline/metamorphic Basement, b) Synrift phase during Paleogene, c) Fast Subsidence from Late Oligocene to Middle Miocene, d) Compressional inversion of first Sunda fold during Late Miocene, and e) Basin Sag during Plio-Pleistocene with mild compressional episodes. The subsequent Mio-Pliocene folding history of Malay Basin is connected to the collision of Sunda Block against subducting Indian–Australian Plate. This Neogene Sunda tectonics, to some degree after the cessation of South China Sea spreading, is due to the diachronous collision along the 1st order plate margins between SE Asia and Australia.

Seismic attributes add a new dimension to prospect evaluation and geomorphology offshore Malaysia

The Malay Basin is a mature Tertiary extensional basin with a later inversion regime in the Late Miocene. The general geology is simple “layer cake” seismically, with some compressive anticlinal inversion structures. The Borneo Basin, on the other hand, is tectonically complex, with steep dips, overthrust, and complex faulting. The rocks are unconsolidated, and geophysical techniques such as amplitude and other attributes should work well. In early years, seismic interpretation was based mostly on mapping structures. The advent of AVO and inversion technologies and pioneering geophysical work brought about increased usage of seismic attributes, solving various problems of geologic interpretation. In Southeast Asia, concentrated efforts since 2000 in seismic data acquisition and processing have resulted in significant improvement in data quality and hence success of attribute application. Seismic imaging and attributes meet challenges such as (1) inversion structural plays in the Malay Basin, (2) stratigraphic channels, (3) fractured basement, (4) deep high-pressure (HP) and high-temperature (HT) plays, (5) steep-dip/overthrust plays, (6) deepwater turbidite plays, (7) carbonate plays of Luconia Province, and (8) thin pay beds, often below seismic resolution, using spectral attributes. Various attributes can be applied to a widespread problem in prospect-maturation evaluation and reservoir characterization.

Wrench-Slip Reversals and Structural Inversions: Cenozoic Slide-Rule Tectonics in Sundaland

DOI: 10.17014/ijog.v1i1.174Most of continental Southeast Asia, that is, Sundaland and Indosinia, achieved a relative tectonic stability by the beginning of the Cenozoic. Since then a strong tectonic activity in Sundaland has been restricted to existing regional fault zones and to regional slow, vertical crustal movements elsewhere that produced small to very large sedimentary basins. On the other hand, regional deformation of Indosinia as a consequence of ductile shearing has continued into the Paleogene. Since the Oligocene, the northern part of Sundaland and Indosinia have been extruded differentially towards southeast along the Red River, Wang Chao (or Mae Ping, or Tonle Sap), and Three Pagodas - Axial Malay fault zones. The initial cause has been attributed to hard collision between Subplate India with Megaplate Eurasia. Plate dynamics in the region have changed substantially since Mid-Miocene as to force wrench-slip reversals along the major fault zones in Sundaland as well as in Indosinia. Concomitant structural inversions are demonstrated on seismic sections. In the core of Sundaland, earlier transtensional wrenching was succeeded by transpressive strike-slip faulting that on major faults of the Malay Basin manifested in reversals of sense. From the Hinge-line fault eastward, the transtensional left wrench slip was succeeded by transpressional dextral slip, while in the region to its west the wrench-slip kinematics was an earlier transtensional right slip followed by transpressional left slip. In the Strait of Malacca and eastern margin of Sumatra, right-lateral wrenching in the Neogene has been common. In certain places it could be established a wrench-slip of transtensional character in Oligocene-Early Miocene, and the transpressional wrench movement occurred mainly during the Middle to Late Miocene. The remarkable coincidence of termination of spreading of the South China Basin in Langhian, and that of the West Philippine and Caroline basins during Mid-Miocene invites further study.

Seismic Illumination Analysis in Poor Oil & Gas Field Data by Using Focal Beam Method

The area underneath shallow gas cloud is an area where the image of subsurface data is generally poor. This distorted image underneath gas zones usually contains precious information of hydrocarbon accumulation. Previously, we analyse the factors contribute to poor subsurface seismic image underneath the gas cloud model and use focal beam technique to understand subsurface illumination information. Encourage by model-based success, we shift our focus to data-based application by applying the focal beam technique into a real field data. The results from this field were analyse in term of resolution function and amplitude versus ray parameter (AVP) imprint for different reflector depth, followed by acquisition analysis on the surface level. For this purpose, a velocity data of a field located in Malay Basin was built before applying the focal beam calculation. We will demonstrate that by using focal beam analysis for this field, we will able to obtain good imaging particularly for target reflector at 2000ms, 4000ms and 6000ms depth, provided the full 3D acquisition geometry was used during focal beam application.

The Attribute for Hydrocarbon Prediction Based on Attenuation

Hydrocarbon prediction is a crucial issue in the oil and gas industry. Currently, the prediction of pore fluid and lithology are based on amplitude interpretation which has the potential to produce pitfalls in certain conditions of reservoir. Motivated by this fact, this work is directed to find out other attributes that can be used to reduce the pitfalls in the amplitude interpretation. Some seismic attributes were examined and studies showed that the attenuation attribute is a better attribute for hydrocarbon prediction. Theoretically, the attenuation mechanism of wave propagation is associated with the movement of fluid in the pore; hence the existence of hydrocarbon in the pore will be represented by attenuation attribute directly. In this paper we evaluated the feasibility of the quality factor ratio of P-wave and S-wave (Qp/Qs) as hydrocarbon indicator using well data and also we developed a new attribute based on attenuation for hydrocarbon prediction -- Normalized Energy Reduction Stack (NERS). To achieve these goals, this work was divided into 3 main parts; estimating the Qp/Qs on well log data, testing the new attribute in the synthetic data and applying the new attribute on real data in Malay Basin data. The result show that the Qp/Qs is better than Poisson's ratio and Lamda over Mu as hydrocarbon indicator. The curve, trend analysis and contrast of Qp/Qs is more powerful at distinguishing pore fluid than Poisson ratio and Lamda over Mu. The NERS attribute was successful in distinguishing the hydrocarbon from brine on synthetic data. Applying this attribute on real data on Malay basin, the NERS attribute is qualitatively conformable with the structure and location where the gas is predicted. The quantitative interpretation of this attribute for hydrocarbon prediction needs to be investigated further.

The basins of Sundaland (SE Asia): Evolution and boundary conditions

Most of the basins developed in the continental core of SE Asia (Sundaland) evolved since the Late Cretaceous in a manner that may be correlated to the conditions of the subduction in the Sunda Trench. By the end of Mesozoic times Sundaland was an elevated area composed of granite and metamorphic basement on the rims; which suffered collapse and incipient extension, whereas the central part was stable. This promontory was surrounded by a large subduction zone, except in the north and was a free boundary in the Early Cenozoic. Starting from the Palaeogene and following fractures initiated during the India Eurasia collision, rifting began along large faults (mostly N–S and NNW–SSE strike-slip), which crosscut the whole region. The basins remained in a continental fluvio-lacustrine or shallow marine environment for a long time and some are marked by extremely stretched crust (Phu Khanh, Natuna, N. Makassar) or even reached the ocean floor spreading stage (Celebes, Flores). Western Sundaland was a combination of basin opening and strike-slip transpressional deformation. The configuration suggests a free boundary particularly to the east (trench pull associated with the Proto-South China Sea subduction; Java–Sulawesi trench subduction rollback). In the Early Miocene, Australian blocks reached the Sunda subduction zone and imposed local shortening in the south and southeast, whereas the western part was free from compression after the Indian continent had moved away to the north. This suggests an important coupling of the Sunda Plate with the Indo-Australian Plate both to SE and NW, possibly further west rollback had ceased in the Java–Sumatra subduction zone, and compressional stress was being transferred northwards across the plate boundary. The internal compression is expressed to the south by shortening which is transmitted as far as the Malay basin. In the Late Miocene, most of the Sunda Plate was under compression, except the tectonically isolated Andaman Sea and the Damar basins. In the Pliocene, collision north of Australia propagated toward the north and west causing subduction reversal and compression in the short-lived Damar Basin. Docking of the Philippine Plate confined the eastern side of Sundaland and created local compression and uplift such as in NW Borneo, Palawan and Taiwan. Transpressional deformation created extensive folding, strike-slip faulting and uplift of the Central Basin and Arakan Yoma in Myanmar. Minor inversion affected many Thailand rift basins. All the other basins record subsidence. The uplift is responsible for gravity tectonics where thick sediments were accumulated (Sarawak, NE Luconia, Bangladesh wedge).

The age, palaeoclimate, palaeovegetation, coal seam architecture/mire types, paleodepositional environments and thermal maturity of syn-collision paralic coal from Mukah, Sarawak, Malaysia

The Mukah coal accumulated in the Balingian Formation where the time-stratigraphic position is poorly defined by fauna, though a probable Late Miocene age has always been assigned to this formation. Samples collected in the present study that yielded an abundance of Casuarina pollen associated with occurrences of Dacrydium, Stenochlaena palustris, Florschuetzia levipoli and also Stenochlaena areolaris spores, compare closely to zone PR9 of the palynological zonation of the Malay Basin, and can be tied to depositional sequences of Malay Basin Seismic sequences I2000/I3000, indicating an Early Miocene age for the studied coal. The Early Miocene age shows that the Mukah coal was formed during the collision between Luconia Block–Dangerous Grounds with the Borneo that lasted from Late Eocene to late Early Miocene. The rapid increase of deposition base-level caused by the collision is clearly reflected by the architecture of the Mukah coal seams that were generally thin, and also by the reverse order of the paleo-peat bodies.The studied coal samples contained large amounts of detrohuminite without the enrichment of liptinite group macerals, usually explained by the dominance of herbaceous plants in the paleomires. However, the pollen assemblages recovered in the present study provide no support for a ‘herbaceous’ swamp, instead the peats were likely formed mainly from forest vegetation based on the recovery of dominant arboreal pollen assemblages in the present study. Palynomorph assemblages recovered in the present study, with abundance of Casuarina pollen associated with common occurrences of Dacrydium, strongly suggest Kerangas vegetation and Kerapah type peat swamps, indicating a very wet climate. The occurrence of rattan and Pandanus pollens shows that the kerapah type peat swamps were locally bordered by rattan and Pandanus swamps. This shows that the prevailing use of coal petrography to discern the type of vegetation that was present in the peat-forming mires may lead to wrong conclusions. Therefore, a multi-disciplinary approach must be applied for a more accurate and reliable spatial interpretation of the type of vegetation that was present in the peat-forming mires.Consistent with the low sulphur content, evidence from the palynomorph assemblages recovered from the coal seams shows that the coal-forming peat was deposited in freshwater mires with little or no marine influence, despite the fact that the accumulation of the Mukah coal-forming peat took place within a coastal plain setting. Moreover, the fauna present in the host rock formation also suggested a brackish-water environment of deposition.

Packer-Leak Repair: Slurry Design and Complex Coiled-Tubing Well Work

This article, written by Dennis Denney, contains highlights of paper IPTC 17091, ’Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,’ by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully. Introduction This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oil reservoirs. In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel. Diagnosis Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations. Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.

Basaltic dykes of the Eastern Belt of Peninsular Malaysia: The effects of the difference in crustal thickness of Sibumasu and Indochina

Basaltic dykes of Peninsular Malaysia are confined to the Eastern Belt (Indochina/East Malaya block) as compared with the Western Belt (Sibumasu Block). The dyke intruded through a crustal fracture formed by stress developed from the evolution of two offshore basins (Malay and Penyu basins) east of Peninsular Malaysia. The Ar–Ar dating from the present study combined with the previous geochronological data indicate that the ages of dykes range from 79±2Ma to 179±2Ma. Thus it is difficult to correlate the dykes with the closure of Tethys during Permo-Triassic time because of the younger age of the dykes. The majority of the dykes exposed in the Eastern Belt may have been attributed to the difference of crustal thickness between the Eastern and Western belt of Peninsular Malaysia. A thicker Western Belt crust (13km more than both Eastern and Central belts) is difficult to rupture with normal plate tectonic stress and therefore serves to contain the rise of a mantle derived melt. The chemistry indicates the basalts are olivine to quartz normative and are of the continental within-plate category.

Evidence for overpressure generation by kerogen-to-gas maturation in the northern Malay Basin

Gas generation is a commonly hypothesized mechanism for the development of high-magnitude overpressure. However, overpressures developed by gas generation have been rarely measured in situ, with the main evidence for such overpressures coming from source rock microfractures, the physical necessity of overpressures for primary migration, laboratory experiments, and numerical modeling. Indeed, previous in-situ observations suggest that gas generation only creates highly localized overpressures within rich source rocks. Pore-fluid pressure data and sonic velocity–vertical effective stress plots from 30 wells reveal that overpressures in the northern Malay Basin are primarily generated by fluid expansion and are located basinwide within the Miocene 2A, 2B, and 2C source rock formations. The overpressures are predominantly associated with gas sampled in more than 83% of overpressure measurements and have a sonic-density response consistent with gas generation. The association of fluid expansion overpressures with gas, combined with the sonic-density response to overpressure and a regional geology that precludes other overpressuring mechanisms, provides convincing in-situ evidence for basinwide gas generation overpressuring. Overpressure magnitude analysis suggests that gas generation accounts for approximately one-half to two-thirds of the measured excess pore pressure in the region, with the remainder being generated by coincident disequilibrium compaction. Thus, the data herein suggest that gas generation, if acting in isolation, is producing a maximum pressure gradient of 15.3 MPa/km (0.676 psi/ft) and not lithostatic magnitudes as commonly hypothesized. The gas generation overpressures in this article are not associated with a significant porosity anomaly and represent a major drilling hazard, with traditional pore-pressure prediction techniques underestimating pressure gradients by 2.3 ± 1.5 MPa/km (0.1 ± 0.07 psi/ft).

Integrating FPWD Measurements With Managed-Pressure Drilling

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 156888, ’Demonstrating the Value of Integrating FPWD Measurements With Managed-Pressure Drilling To Drill Narrow Mud-Weight Windows Safely in an HP/HT Environment,’ by L. Umar, SPE, I. Azian, N. Azree, and A.R.M. Ali, Petronas, and A. Waguih, SPE, F. Rojas, SPE, S. Fey, SPE, B. Subroto, SPE, B. Dow, and G. Garcia, SPE, Schlumberger, prepared for the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, 20-21 March. The paper has not been peer reviewed. A high-pressure/high-temperature (HP/HT) exploration field in Block PM on the northern side of the Malay basin, Malaysia, is notorious for a steeply rising pressure ramp, narrow drilling-operation window (only 0.5 to 0.6 lbm/gal in the 14¾ and 9½-in. sections), and interbedded sand/coal and shale formations. Block PM is still in the exploration-and-appraisal stage; therefore, petrophysical information is limited. Well SBD-2 was the second attempt to reach and cross the F and H sands. Formation-pressure-while-drilling (FPWD) and managed-pressure-drilling (MPD) technologies were applied to drill this well. FPWD provided a direct pressure measurement while drilling to set the lower boundary, and formation-integrity tests (FITs) with MPD provided the upper boundary. Introduction The SB field has a relatively high temperature gradient and abnormal-pressure regimes. Challenges in this HP/HT environment include a reduced kick tolerance, narrow drilling margin, higher drilling-fluid densities, high temperature (limitations in formation-evaluation equipment), wellbore ballooning, and availability of personnel experienced in HP/HT drilling. Well SBD-2 had been considered undrillable because of its very narrow safe-drilling margin. The previous attempt to drill through the F and H reservoir sands, Well SBD-1, suffered an influx from the formation that exceeded kick tolerance and compromised the fracture gradient, resulting in total fluid losses. Well SBD-1 failed to reach total depth (TD) despite the use of an MPD system—200 m shy of the geologic target. Well SBD-2 was drilled only 50 m away from Well SBD-1. Given the close proximity, there were offset pressure data for planning Well SBD-2 down to a depth of X240 m, but beyond this depth it would be exploratory drilling. Given the uncertainties that would be encountered drilling past X240 m, the engineering team sought best practices and technologies that would provide the greatest chance of success drilling into such a tight margin at high temperature. The 8½×9½-in. reservoir section would use an automated MPD system to mitigate drilling risk complemented by an FPWD tool in the drilling bottomhole assembly (BHA) to provide direct pressure measurements. The MPD sys-tem was used for early kick detection (EKD), FITs, dynamic flow checks, and constant-bottomhole-pressure (CBHP) control for a safe mud-weight window that was expected to be less than 0.9 lbm/gal. The high mud weight needed to drill this formation resulted in a high equivalent circulating density (ECD) throughout the section, requiring the MPD system to maintain a static condition between 0.2 and 0.4 lbm/gal. The FPWD tool would provide pressure data to establish the lower limit for the MPD fingerprint tests, and to serve as calibration points for the pore-pressure model. The objective in this 8½×9½-in. section was to maintain overbalance in the narrow window between pore pressure and fracture gradient. These tight drilling margins required use of an automated MPD system with software capable of predicting temperature effects and annular-pressure behavior during any well-control situation.

FORMING CONDITIONS OF HYDROCARBON RESERVOIR AND OIL ENRICHMENT MECHANISMS OF PRE-I GROUP (OLIGOCENE-LOWER MIOCENE) IN MALAY BASIN

The J、K、L and M groups(Pre-I group,Oligocene-lower Miocene)have good conditions for hydrocarbon accumulation in the Malay Basin.①Tectonic movements favor the accumulation of hydrocarbon.In early Miocene,the stage of extensional fracturing,numerous lacustrine source rocks were deposited.In early-middle Miocene,the stage of tectonic subsidence,accompanied by basin inversion,reservoir and seal systems of the Pre-I group's petroleum system were formed.②The lacustrine deposits are excellent source rocks,which are rich in algae and have higher maturity and organic content.③Reservoirs are available,such as the braided river sandstone in the K group and the estuarian channel sandstone and intertidal sandstone in the J group.④Cap rocks are well developed.The main cap rock of Pre-I group is the delta-shallow marine mudstone deposited in the transgressive period of the Basin.The secondary cap rock is the lacustrine mudstone in K、L and M groups.⑤Migration pathways are still open.Both upward and lateral migration occurs ⑥The source-reservoir-seal assemblages are favorable.Both the self generation and self preservation assemblage and lower generation and upper preservation assemblage occur,which are favorable to oil and gas accumulation.The petroleum system of Pre-I group is located in the southeastern part of the Malay Basin.The oil and gas distribution in the Malay Basin is controlled by the distribution、quality and maturity of source rocks、forming time of structures and the migration of hydrocarbon.

Investigating the impact of acquisition design on the problem of imaging below shallow gas

SummaryThe problem of shallow, highly absorptive zones negatively affecting the quality of the seismic image at target depth is widespread across the Malay Basin. Whilst developments in processing regimes have lead to considerable improvements in the compensation of amplitudes below these areas of high absorption, the issue of improving the seismic image, and subsequently, our confidence in exploration decisions within affected fields remains a key challenge for operators in this region.This study investigates the impact that acquisition geometry and design can have on the problem of imaging below shallow gas. Using advanced ray-based modeling techniques, we take a detailed look at the improvements in sub-gas amplitudes afforded by adopting nonconventional acquisition geometries; including, but not limited to, the large-offset (approx. 14 km), full-azimuth, dual coil shooting approach recently used in the Gulf of Mexico and broad-bandwidth acquisition techniques.In addition to the illumination and amplitude characteristics associated with each design, we also investigate the improvements in resolution by simulating 3D prestack depth migration (PSDM) cubes at key areas of interest to try to understand the additional benefits afforded by adopting a non-conventional approach to acquisition.Through the use of forward modeling, we provide a comprehensive insight into whether non-conventional acquisition techniques have a role to play in addressing the problem of imaging below zones of high absorption located in the overburden.

Review of pore-pressure prediction challenges in high-temperature areas

Pore-pressure prediction relies heavily on interpretation of seismic and well attributes such as velocity, resistivity, and density which capture porosity changes during shale compaction under vertical loading. Relationships such as Eaton (1975) were developed in the Gulf of Mexico using a relatively simple lithological mix of geologically young sandstones and shale mudrocks at relatively low temperatures. An alternative approach using data from the same region was more deterministic°also with vertical stress (e.g., Hottman and Johnson, 1965; Bowers, 1995). Another approach using mean stress, developed by Harrold et al., (2000) used similar sand and shale sequences at relatively low temperatures from data in southeast Asia basins. All the above approaches can be shown to provide acceptable prediction of pore pressure in shale mudrocks in young, rapidly deposited siliciclastic sequences, such as the Baram Delta, Brunei (Tingay et al., 2009) and along the West African margin (Swarbrick et al., 2011). The results can be calibrated, with careful attention to evidence for lateral drainage or lateral transfer, using data from their associated reservoir. However, in higher-temperature environments (e.g., Malay Basin, Hoesni 2004) these methods fail to deliver predictions, which may be accurate enough for effective well planning and safe drilling. This paper reviews the above methods and how they can be modified for use at elevated temperatures (e.g., above 100°C). However, the review also draws attention to the wide uncertainty inherent in conventional approaches to prediction in some regions, which may require an entirely different approach to pore-pressure prediction prior to drilling.

Automated Managed-Pressure Drilling Helps Find Reserves Near Failed Exploration Well

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151518, ’Automated Managed-Pressure Drilling Allows Identification of New Reserves in an HP/HT Exploration Well in SB Field, Offshore Malaysia,’ by Zulkarnain Ismail, Intan Azian Bt. A. Aziz, Lawrence Umar, SPE, Noor Azree B. Nordin, SPE, and Thanavathy Patma Nesan, Petronas, and Freddy Rojas Rodriguez, Fernando Gallo Zapata, Greg Garcia, Ahmed Waguih, SPE, Bramanta Subroto, and Blaine Dow, SPE, Schlumberger, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. The SB field in Block PM on the west side of the Malay basin, Malaysia, is notorious for its steeply rising pressure ramp, narrow drilling operation window, and interbedded sand, coal, and shale formations. Well SBD-2 was the second attempt to reach and cross the F and H sands of this basin. Despite using managed-pressure drilling (MPD), the first attempt failed when an influx exceeded the fracture gradient, resulting in total fluid losses. Because of the shallow pressure ramp and narrow window between pore pressure and fracture gradient, a repeat attempt was initially deemed undrillable. However, the design team felt the target could be reached using automated MPD. Introduction The SB field is considered a very challenging area because the pressure and temperature in the depositional environment are abnormally higher than in neighboring fields. Some of the key challenges with this high-pressure/high-temperature (HP/HT) environment are reduced kick tolerance, narrow drilling window between pore pressure and fracture gradient, higher drilling-fluid densities, temperature limitation on formation-evaluation bottomhole-assembly components that limits data acquisition, wellbore ballooning and breathing, and number of personnel with HP/HT drilling experience. The original well, SBD-1, was only 50 meters away from Well SBD-2. Despite using MPD, the first attempt failed when an influx exceeded kick tolerance and compromised the fracture gradient, resulting in total fluid losses. The failed well cost more than USD 30 million and reached only the F sand, 200 m shy of the geologic target. The offset data gathered from that well helped with the planning of SBD-2 down to X240 m. The full capabilities of an automated MPD system were applied to mitigate drilling risk. The MPD system was used for early kick detection (EKD), dynamic formation-integrity tests (FITs), dynamic flow checks, and constant-bottomhole-pressure (CBHP) control. With a mud-weight window of less than 0.9 ppg, the system was required to detect and control kicks, identify and control ballooning effects, and maintain the bottomhole pressure (BHP) within the tight high-pressure window. In total, three sections were drilled with the automated MPD system. The 8½×14¾-in. section required minimum overbalance to manage wellbore breathing and to control potential losses to weaker horizons. In the 10½×12¼-in. section, the system was used to identify and react quickly to kicks in high-pressure sands and also to eliminate wellbore breathing and ballooning. In the final section (8½×9½ in.), the objective was to maintain overbalance in the narrow pressure window between pore pressure and fracture gradient.

Spar platform at deep water region in Malaysian sea

Exploration of oil and gas resources has been accelerated towards deeper waters due to depletion of their reserve in shallow water depth. Malaysian sedimentary basins signpost the existence of these energy sources below its sea-bed. In deep sea depth, traditional fixed types of offshore structures to explore these resources have become incongruous and they have resorted to new configurations. Spar platform is treated as a cost-effective and efficient compliant floating platform in this locale for drilling, production, processing and storage of ocean deposits. This study deals with the oil and gas eminence in Malaysian sea along with structural response behaviors of spar platform subjected to hydrodynamic loading. A single model of spar-mooring line combination has been developed. Coupled conduct has been computed under unidirectional wave loading where all non-linearities are incorporated. Solution in time domain approach follows Newmark-beta integration technique. It is seen that the continental shelf offshore of Malaysian waters is divided into seven sedimentary basins, out of which three basins have major ongoing oil and gas exploration and production activity, namely the Malay basin in West Malaysia off Terengganu and the Sabah and Sarawak basins off the two East Malaysian states of Sabah and Sarawak, respectively. Surge, heave, pitch motion response of spar hull and tension in mooring line tension have been evaluated. Spar platform indicates itself as advanced and competent offshore structures to enhance the oil and gas exploration from all the Malaysian sedimentary basins in the deep water region.

Drilling Highly Depleted Formations With Engineered-Particle Nonaqueous Fluids: South China Sea

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139932, ’Drilling Highly Depleted Formations With Engineered- Particle Nonaqueous Fluids: South China Sea,’ by Michael R. Niznik, SPE, Adela Lawrence, SPE, and Sabine C. Zeilinger, SPE, ExxonMobil, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. A new engineered-particle nonaqueous-fluid (EP-NAF) system was used in the Malay basin of the South China Sea to drill through highly depleted sands at elevated densities. The fluid contains sized particles to bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical-path rig time. Background and Well-Design Overview The Malay basin in the South China Sea contains multiple oil and gas accumulations, some of which have been on production for several decades. Many of these mature fields have economically recoverable quantities of hydrocarbons but are challenging because depleted zones are adjacent to formations prone to wellbore instability. A four-well infill development program was planned in one of these mature fields. The field is 200 km offshore in 70 m of water. Several platforms were installed to develop the field, which has been producing for more than 20 years. Typically, tender-assisted platform rigs are used in this field. Well-Design Challenges and Planning All proposed wells would be side-tracked from existing donor wellbores. A variety of casing sizes was used in the donors, and exact cement tops were not known. The exact sidetrack point was engineered to take into account collision avoidance of offset wells, cement behind casing, formations in which to sidetrack, and dogleg requirements to meet geology and reservoir objectives. The target reservoir was the Group-J sands that lie below the Group-I reservoir, which was completed and put on production more than 20 years earlier. The pore pressure of the Group-I reservoir in the area where the proposed wells would penetrate was determined to be depleted to a 3.7-lbm/gal gradient. The target Group-J sands also were slightly depleted to a 6.8-lbm/gal gradient because of production in adjacent fault blocks. The targeted Group-J reservoir has lower-permeability sands compared with the Group-I reservoir above it. Horizontal wells were planned to intersect additional reservoir footage and to maximize productivity and reserves recovery. The Group-J sands are highly consolidated, and modeling, along with offset-well analysis, determined that sand control would not be required. The wells could be completed open hole with predrilled liners, which minimized completion complexity and cost.

Modeling of petroleum generation in the Vietnamese part of the Malay Basin using measured kinetics

Two-dimensional (2-D) modeling of source rock maturation and hydrocarbon (HC) generation histories were conducted for the Malay-Cho Thu Basin in the Gulf of Thailand and South China Sea. The source rocks comprise Oligocene synrift lacustrine mudstones and coals, postrift coals, and terrigenous-influenced mudstones. Three different lacustrine mudstone source rocks and coals were considered in the 2-D modeling, and each source rock was assigned specific generation potential and kinetics. Measured kinetics for bulk petroleum generation determined on two thermally immature upper Oligocene oil-prone lacustrine mudstones and on a terrigenous-influenced mudstone derived from wells were used together with published coal kinetics. The onshore Krong Pa graben, a small-scale rift basin in central Vietnam, was used as a conceptual model for the distribution of lithofacies, including source rock types, in the 2-D models. Exploration targets and drilled direct HC indicators (DHIs) are mainly located in the tectonically disturbed postrift succession. Modeling results suggest that the risks related to this play are (1) timing of petroleum generation from the oil-prone lacustrine synrift deposits relative to structural trap formation, (2) complex migration pathways through strongly faulted strata, and (3) relatively small kitchen areas. Oil generation from uppermost synrift and postrift coaly source rocks with minor contribution from lacustrine deposits after principal trap formation is consistent with the prominent terrigenous geochemical signature of oils in the Malay-Cho Thu Basin. A new untested play is proposed based on mapping of potential DHIs associated with sandstone bodies in tectonically undisturbed synrift traps.

Organic facies variation in lacustrine source rocks in the southern Malay Basin

Organic facies variation in lacustrine source rocks in the southern Malay Basin