ALBERT

Description: Shale dykes, diapirs and mud volcanoes are common in the onshore and offshore regions of Brunei Darussalam. Outcrop examples show that shale has intruded along both faults and tensile fractures. Conventional models of overpressure-induced brittle failure assume that pore pressure and total stresses are independent of one another. However, data worldwide and from Brunei show that changes in pore pressure are coupled with changes in total minimum horizontal stress. The pore pressure/stress-coupling ratio ({Delta}{sigma}h/{Delta}Pp) describes the rate of change of minimum horizontal stress magnitude with changing pore pressure. Minimum horizontal stress measurements for a major offshore field where undepleted pore pressures range from normal to highly overpressured show a pore pressure/stress-coupling ratio of 0.59. As a consequence of pore pressure/stress coupling, rocks can sustain a greater increase in pore pressure prior to failure than predicted by the prevailing values of pore pressure and stress. Pore pressure/stress-coupling may favour the formation of tensile fractures with increasing pore pressure rather than reactivation of pre-existing faults. Anthropogenically-induced tensile fracturing in offshore Brunei supports this hypothesis.

Description: High-pressure sediments in which oil and gas are generated and accumulate in traps are proven in many operating areas along the entire West African margin. Although classic areas for high pressure are found in Tertiary deltas, such as the Niger Delta, other types of basins in which young clastic sediments have accumulated also create the environment for high pressure and drilling challenges. The BP Macondo oil spill in the Gulf of Mexico has highlighted the technical challenge of drilling for oil in deep water, and the high pressures there added complexity to the control incident and the high volumes of fluids which blew out to the seabed.

Description: Analysis of subsurface pressure data from Taranaki Basin using direct (e.g., repeat formation tester) and indirect measurements (drilling parameters and wireline log data such as sonic and resistivity) indicates the presence of three pressure zones: a near-hydrostatic regime (zone A) that extends across the entire basin and to varying depths; an underlying overpressured regime (zone B), with pressures approximately 1100 psi (7.584 MPa) above hydrostatic, that extends throughout the Manaia graben and north along the eastern basin margin at depths of 1900 to 4100 m (6234-13,451 ft); and a third regime (zone C), with approximately 2100 psi (14.479 MPa) overpressure, that directly underlies zone A and zone B in different parts of the basin (although well penetrations are limited). The primary cause of overpressure is interpreted to be disequilibrium compaction preserved in upper Eocene and Oligocene marine shales. In parts of the basin, hydrocarbon generation (and in particular cracking to gas at high maturities) is interpreted to contribute to overpressures. The overpressures drain laterally and vertically into permeable units. Intervening transition zones (seals) comprise lithologic boundaries, diagenetic zones, and fault planes. Oligocene carbonates, although commonly thin, provide an effective barrier to vertical hydraulic communication over much of the basin. The Manaia graben is a partially closed system, with overpressures retained by a complex combination of a top shale seal overlying a regional sequence boundary, lithologic barriers within fault compartments, fault planes, and subcropping sequences; episodic fault breach enables vertical transfer of fluids from zone B to zone A in a dynamic fault valve process. To date, all oil reserves have been found in zone A, a large proportion of gas-condensate reserves are within zone B, and no commercial reserves have been established within zone C. The spatial definition of these zones and the appropriate pressure regime is important for well design, drilling safety, determining hydrocarbon column heights and gas expansion factors, and for exploration migration analysis. Regional analysis of pressure regimes can identify subsurface barriers and seals. Faults, in particular, are key elements in fluid migration and the focusing of liquids at abrupt pressure transitions. The strength of fault planes and diagenetic zones is the likely control on dynamic fluid release. Zone C has been very lightly explored and may represent a potential for large dry-gas accumulations; the zone may be sealed by a diagenetic zone crosscutting lithologic boundaries (conventional mapping horizons).

Description: Journal of Medicinal Chemistry DOI: 10.1021/jm501037u

Description: Accurate pore-pressure prediction is critical in hydrocarbon exploration and is especially important in the rapidly deposited Tertiary Baram Delta province where all economic fields exhibit overpressures, commonly of high magnitude and with narrow transition zones. A pore-pressure database was compiled using wireline formation interval tests, drillstem tests, and mud weights from 157 wells in 61 fields throughout Brunei. Overpressures are observed in 54 fields both in the inner-shelf deltaic sequences and in the underlying prodelta shales. Porosity vs. vertical effective stress plots from 31 fields reveal that overpressures are primarily generated by disequilibrium compaction in the prodelta shales but have been generated by fluid expansion in the inner-shelf deltaic sequences. However, the geology of Brunei precludes overpressures in the inner-shelf deltaics being generated by any conventional fluid expansion mechanism (e.g., kerogen-to-gas maturation), and we propose that these overpressures have been vertically transferred into reservoir units, via faults, from the prodelta shales. Sediments overpressured by disequilibrium compaction exhibit different physical properties to those overpressured by vertical transfer, and hence, different pore-pressure prediction strategies need to be applied in the prodelta shales and inner-shelf deltaic sequences. Sonic and density log data detect overpressures generated by disequilibrium compaction, and pore pressures are accurately predicted using an Eaton exponent of 3.0. Sonic log data detect vertically transferred overpressures even in the absence of a porosity anomaly, and pore pressures are reasonably predicted using an Eaton exponent of 6.5. Mark Tingay is currently an Australian postdoctoral fellow at Curtin University, where he works on stress, overpressure, and the tectonic evolution of Southeast Asia. He received his Ph.D. in 2003 from the Australian School of Petroleum. He then became a petroleum geomechanics researcher at the World Stress Map Project, where he worked on projects in 11 countries, including the United States, Egypt, Azerbaijan, and Thailand. Richard Hillis is the head of the Australian School of Petroleum and a state of South Australia professor of petroleum geology at the University of Adelaide. He received his B.Sc. (hons) degree from Imperial College and Ph.D. from the University of Edinburgh. He is a director of JRS Petroleum Research, an image log and geomechanics consulting company, and of Petratherm, a geothermal exploration company. Richard commenced his career in 1979 when he joined Mobil with assignments in the United Kingdom and the United States. He joined Durham University in 1989 and was a principal investigator for a multidisciplinary research group funded by 17 oil and gas companies. Over that period, he developed training courses in subsurface pressures and founded the company GeoPressure Technology. He is an honorary professor at Durham University and has been an AAPG member since 1982. Chris received his Ph.D. in 1983 before working for Amoco and Elf Aquitaine and as a professor at the University of Brunei Darussalam. He is currently working for PTT Exploration and Production as a senior geophysicist. He has worked as an exploration geologist and as a structural geologist in east Africa, Morocco, the Norwegian Caledonides, the Carpathians, northwest Borneo, and Thailand. Abdul Razak Damit is currently the chief geologist with the National Oil Company of Brunei (PetroleumBRUNEI). He obtained his Ph.D. at Aberdeen University and has 20 years of industry experience, primarily in Shell where he worked on both reservoir and regional evaluation. His main interests are in the geology of northwest Borneo and in raising public awareness of the natural and social history of Brunei.

Description: The present-day state of stress in Tertiary deltas is poorly understood but vital for a range of applications such as wellbore stability and fracture stimulation. The Tertiary Baram Delta province, Brunei, exhibits a range of contemporary stress values that reflect the competing influence of the northwest Borneo active margin (situated underneath the basin) and local stresses generated within the delta. Vertical stress (σv) gradients at 1500-m (4921-ft) depth range from 18.3 MPa/km (0.81 psi/ft) at the shelf edge to 24.3 MPa/km (1.07 psi/ft) in the hinterland, indicating a range in the shallow bulk density across the delta of 2.07–2.48 g/cm3. The maximum horizontal stress (σHmax) orientation rotates from margin parallel (northeast–southwest; deltaic) in the outer shelf to margin normal (northwest–southeast; basement associated) in the inner shelf. Minimum horizontal stress (σhmin) gradients in normally pressured sequences range from 13.8 to 17.0 MPa/km (0.61–0.75 psi/ft) with higher gradients observed in older parts of the basin. The variation in contemporary stress across the basin reveals a delta system that is inverting and self-cannibalizing as the delta system rapidly progrades across the margin. The present-day stress in the delta system has implications for a range of exploration and production issues affecting Brunei. Underbalanced wells are more stable if deviated toward the σhmin direction, whereas fracture stimulation in mature fields and tight reservoirs can be more easily conducted in wells deviated toward σHmax. Finally, faults near the shelf edge are optimally oriented for reactivation, and hence exploration targets in this region are at a high risk of fault seal breach. Mark Tingay is currently an Australian postdoctoral fellow at Curtin University, where he works on stress, overpressure, and tectonic evolution of Southeast Asia. He received his Ph.D. in 2003 from the Australian School of Petroleum. He then became the petroleum geomechanics researcher at the World Stress Map Project where he worked on projects in 11 countries, including the United States, Egypt, Azerbaijan, and Thailand. Richard Hillis is the head of the Australian School of Petroleum and State of South Australia professor of petroleum geology at the University of Adelaide. He received a B.S. degree (hons) from Imperial College and a Ph.D. from the University of Edinburgh. He is a director of image log and a geomechanics consultant of JRS Petroleum Research and of the geothermal exploration company Petratherm. Chris Morley received his Ph.D. in 1983 before working for Amoco and Elf Aquitaine and as a professor at the University of Brunei Darussalam. He is currently working for PTT Exploration and Production as a senior geophysicist. He has worked as an exploration geologist and as a structural geologist in east Africa, Morocco, the Norwegian Caledonides, the Carpathians, northwest Borneo, and Thailand. Rosalind King is a postdoctoral researcher at the Australian School of Petroleum where she studies the present-day stress and neotectonics of northwest Borneo as well as delta and deep-water fold and thrust belt systems worldwide. She completed her Ph.D. on the structural evolution of the Cape fold belt and southwest Karoo Basin, South Africa. Richard Swarbrick commenced his career in 1979 when he joined Mobil with assignments in the United Kingdom and the United States. He joined Durham University in 1989 and was a principal investigator for a multidisciplinary research group funded by 17 oil and gas companies. Over that period, he developed training courses in subsurface pressures and founded the company GeoPressure Technology. He is an honorary professor at Durham University and has been an AAPG member since 1982. Abdul Razak Damit is currently the chief geologist for the National Oil Company of Brunei (PetroleumBRUNEI). He obtained his Ph.D. at Aberdeen University and has 20 years of industry experience, primarily at Shell where he worked on both reservoir and regional evaluation. His main interests are in the geology of northwest Borneo and in raising public awareness of the natural and social history of Brunei.

Description: Analysis of subsurface pressure data from Taranaki Basin using direct (e.g., repeat formation tester) and indirect measurements (drilling parameters and wireline log data such as sonic and resistivity) indicates the presence of three pressure zones: a near-hydrostatic regime (zone A) that extends across the entire basin and to varying depths; an underlying overpressured regime (zone B), with pressures approximately 1100 psi (7.584 MPa) above hydrostatic, that extends throughout the Manaia graben and north along the eastern basin margin at depths of 1900 to 4100 m (6234–13,451 ft); and a third regime (zone C), with approximately 2100 psi (14.479 MPa) overpressure, that directly underlies zone A and zone B in different parts of the basin (although well penetrations are limited). The primary cause of overpressure is interpreted to be disequilibrium compaction preserved in upper Eocene and Oligocene marine shales. In parts of the basin, hydrocarbon generation (and in particular cracking to gas at high maturities) is interpreted to contribute to overpressures. The overpressures drain laterally and vertically into permeable units. Intervening transition zones (seals) comprise lithologic boundaries, diagenetic zones, and fault planes. Oligocene carbonates, although commonly thin, provide an effective barrier to vertical hydraulic communication over much of the basin. The Manaia graben is a partially closed system, with overpressures retained by a complex combination of a top shale seal overlying a regional sequence boundary, lithologic barriers within fault compartments, fault planes, and subcropping sequences; episodic fault breach enables vertical transfer of fluids from zone B to zone A in a dynamic fault valve process. To date, all oil reserves have been found in zone A, a large proportion of gas-condensate reserves are within zone B, and no commercial reserves have been established within zone C. The spatial definition of these zones and the appropriate pressure regime is important for well design, drilling safety, determining hydrocarbon column heights and gas expansion factors, and for exploration migration analysis. Regional analysis of pressure regimes can identify subsurface barriers and seals. Faults, in particular, are key elements in fluid migration and the focusing of liquids at abrupt pressure transitions. The strength of fault planes and diagenetic zones is the likely control on dynamic fluid release. Zone C has been very lightly explored and may represent a potential for large dry-gas accumulations; the zone may be sealed by a diagenetic zone crosscutting lithologic boundaries (conventional mapping horizons). Mark Webster is gas exploration manager at Genesis Energy. Since graduating from Victoria University in Wellington in 1982, he has worked for a variety of companies in exploration programs in New Zealand, Australia, Thailand, Philippines, Malaysia, and Canada, including roles as chief geologist at Petrocorp Exploration and exploration manager at Santos and TAG Oil. He is a member of the Petroleum Exploration Society of Australia and has been a member of AAPG since 1982. Stephen O'Connor is technical manager at GeoPressure Technology (Ikon Science Group), supervising pressure projects around the world, including Europe, Black Sea, West Africa, and Trinidad. He specializes in producing pore and fracture pressure profiles using direct pressure measurements, petrophysical logs, and seismic velocity data for use in well planning, as well as both field and regional studies. He holds a B.S. degree in geological sciences from Leeds University and an M.S. degree from Reading University (Sedimentology). Bitrus Pindar is currently a petroleum geoscientist at Geopressure Technology Limited. Before joining GeoPressure Technology, he served as a regional geologist at the Nigerian Geological Survey Agency, Abuja. He holds a B.S. degree in geology from the University of Maiduguri and an M.S. degree in petroleum geoscience from Imperial College London. He is a member of AAPG and Petroleum Exploration Society of Great Britain. Richard Swarbrick holds a Ph.D. in sedimentology/tectonics from Cambridge University and commenced his career in 1979 when he joined Mobil, with assignments in the United Kingdom and the United States. He joined Durham University in 1989 and was a principal investigator for a multidisciplinary research group funded by 17 oil and gas companies. During that period, he developed training courses in subsurface pressures and founded the company GeoPressure Technology. He is an honorary professor at Durham University and has been an AAPG member since 1982.