Bandar Seri Begawan, Brunei
Bandar Seri Begawan, Brunei

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King R.C.,University of Adelaide | Hillis R.R.,University of Adelaide | Tingay M.R.P.,University of Adelaide | Tingay M.R.P.,Brunei Shell Petroleum Co. | And 2 more authors.
Basin Research | Year: 2010

The Baram Delta System, Brunei, NW Borneo, is a Tertiary delta system located on an active continental margin. Delta top regions in many Tertiary delta systems (e.g. Niger Delta) are thought to exhibit a normal-fault stress regime and margin-parallel maximum horizontal stress orientations. However, unlike in passive margin Tertiary delta systems, two present-day stress provinces have been previously identified across the Baram Delta System: an inner shelf inverted province with a margin-normal (NW-SE) maximum horizontal stress orientation and an outer shelf extension province with a margin-parallel (NE-SW) maximum horizontal stress orientation. Before this study, there were few data constraining the inverted province other than in the vicinity of the Champion Fields. New data from 12 petroleum wells in the western inner shelf and onshore west Brunei presented herein confirm the margin-normal maximum horizontal stress orientations of the inverted province. A total of 117 borehole breakouts, all documented in shale units, and one drilling-induced tensile fracture (in a sandstone interval) reveal a mean maximum horizontal stress orientation of 117 with a standard deviation of 19°. This orientation is consistent with contemporary margin-normal maximum horizontal stress orientations of the inverted province described previously in the vicinity of the Champion Fields that have been linked to basement tectonics of the Crocker-Rajang accretionary complex and associated active margin. However, stress magnitudes calculated using data from these 12 petroleum wells indicate a borderline strike-slip fault to normal fault stress regime for the present day; combined with the absence of seismicity, this suggests that the studied part of the NW Borneo continental margin is currently tectonically quiescent. © 2009 The Authors. Journal Compilation © Blackwell Publishing Ltd, European Association of Geoscientists & Engineers and International Association of Sedimentologists.

Alger W.D.,Brunei Shell Petroleum Co. | Van Den Heuvel E.,Brunei Shell Petroleum Co.
EAGE/FESM Joint Regional Conference Petrophysics Meets Geoscience: From Nano Pores to Mega Structures | Year: 2014

Saturation evaluation from petrophysical logs is problematic in Brunei reservoirs due to the clay rich formations. Laminated and disseminated clays are common throughout reservoir units resulting in a suppression of resistivity log responses. Saturation height models based on capillary pressure data are often not possible as core recovery and the vintage of much of the core results in limited special core analysis measurements. Through careful quality control of capillary pressure curves a combined database covering all major Brunei reservoirs has been compiled. Saturation trends from capillary pressure curves based on reservoir permeability have been developed and shown to be consistent across the combined field's data. This larger data set enables development of robust saturation modelling trends for fields with a very limited capillary curve database.

Pinillos C.,Brunei Shell Petroleum Co. | Rong Y.C.,Brunei Shell Petroleum Co.
Society of Petroleum Engineers - SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, APOGCE 2015 | Year: 2015

Development of computer processing capability has helped nowadays to develop tools that are not only able to interpret a single Build-up or Drawdown but instead the whole pressure history acquired during welltest or the whole life of the well (when Permanent Down-Hole Gauges, PDHG, are available) by using either analytical solutions or numerical simulation techniques. The use of recorded bottom-hole pressure during welltests to conduct Pressure Transient Analysis (PTA) should not be limited to classical approach of determining permeability and skin parameters. Moreover, when PTA is used in combination with classic Reservoir Engineering tools such as Material Balance and Rate Transient Analysis (RTA), then it can be very useful in Reservoir Characterization, Reconciliation of Initial in Place Volume obtained from different techniques and Identification of main Drive Reservoir Mechanism. This paper describes the successful implementation of the aforementioned Pressure Transient Analysis applications in a Gas Field where the main uncertainties identified during the Field Development Plan (FDP) stage were: 1) Initial in Place Volumes, mainly as result of uncertainty of the Gas Water Contact (GWC) depth in the deeper reservoirs, 2) Connectivity between blocks, due to a fault presence and 3) Aquifer pressure support. A deviation of historical pressure behavior from the Field Development Plan estimates was observed, which resulted in: a) Revisit of the assumptions made in the FDP and b) Re-evaluation of the Gas Initial In-Place Volumes (GIIP). The Integration of PTA, Material Balance and RTA together with the incorporation of 3-4 years of production and pressure history has proved to be a good practice to understand and characterize the reservoir allowing different methods (Volumetric, Material Balance, Rate Transient Analysis) to converge to a similar GIIP estimates. Copyright 2015, Society of Petroleum Engineers.

Turner R.,Brunei Shell Petroleum Co.
Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012 | Year: 2012

In 1999 Brunei Shell Petroleum (BSP) completed its first Smart Well, leading to over 100 Smart Wells being installed over the subsequent decade. BSP defines Smart as having remotely operated control devices in the completion string; a well only containing a downhole pressure gauge is not considered Smart. Typical wells in Brunei intersect multi-layered reservoirs containing oil, water and/or gas, many of them oil rims. The relatively low hydrocarbon volume per reservoir requires each well to develop numerous reservoirs in order to be economic. Smart completions allow flow to be controlled on a per zone basis, enabling different dynamic reservoir responses to be managed over the field life (e.g. by controlling drawdown or optimising gas development). This ability, particularly for oil rims, has enabled BSP to develop fields that would not have been sanctioned otherwise. Obtaining optimum value from Smart Wells is demanding. Additional resources are required as more data needs to be reviewed and more frequently, in order to perform the many zonal optimisations necessary for optimum reservoir management. Workflows become more complex, additional interfaces with other disciplines are required and new work competencies need to be acquired. The challenge for operators contemplating the use of Smart Technology is that Smart Capabilities are required in all major company departments. Subsurface teams need to justify Smart requirements in Field Development Plans, Well Engineering want to standardise Smart completions, Production Departments require processes to efficiently maximise lifecycle production, whilst IT personnel have to provide reliable two way communications between the wells and head office. Smart completions lend themselves to being able to prove to stakeholders that fields are being optimally managed, particularly with regards to reserves recovery. In the future having Smart Field capability may become a requirement as opposed to an option, possibly turning it into a licence to operate. Copyright 2011, International Petroleum Technology Conference.

Talib N.,Brunei Shell Petroleum Co. | Omar A.S.,Brunei Shell Petroleum Co.
Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012 | Year: 2012

The West Asset of Brunei Shell Petroleum (BSP) is an offshore-based oil & gas production asset with substantial volumes of non-associated gas from deep, low permeability reservoirs. The typical depths of these reservoirs are from ca. 9000 ft to 11000 ft tvdss having a permeability range of 0.1 - 10 mD and porosity range of 9% - 13%. In the past, the completion type for the deep, tight gas reservoirs has been primarily cased-hole and perforated. The production rates has not been sustainable and was observed to decline faster than expected and ceased production, at reservoir pressures significantly higher than expected abandonment pressure. Investigation showed that these wells quit prematurely due to high skin, although the actual damage mechanism i.e. from fines migration, condensate banking, water banking or clay swelling, is still unknown. Production remediation via acid stimulation and through-tubing re-perforation did not achieve the desired results. Consequently, there is a demand for the West Asset to pursue different completion strategies primarily dedicated to develop deep, tight gas reservoirs. Hydraulic fracturing is one of the completion concepts proposed to test the reservoir producibility performance. Other than a failed "Skin-Frac" campaign attempt in the past, hydraulic fracturing technology has not been widely applied in BSP. With a lack of geomechanics data and fracturing experience, a number of challenges were confronted during well planning and completion design phase as well as during planning and execution of the hydraulic fracturing campaign. In the past two years, two wells have been hydraulically fractured by bull heading through 4-1/2'' monobore completion via frac boat. Therefore, this case study documents the evolvement of completion and hydraulic fracturing strategies, emphasizing the importance of perforation selection, fluid selection and hydraulic fracture designs to the overall outcome of well performance. This paper also captures the operational challenges and learnings experienced throughout the campaign. This campaign has gathered valuable information on fracturing data and provided better understanding on future completion and fracturing approaches for new tight gas wells in the West Asset and similar assets in Brunei. Copyright 2011, International Petroleum Technology Conference.

Church J.,Brunei Shell Petroleum Co. | Yuk B.P.,Brunei Shell Petroleum Co.
Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012 | Year: 2012

The onshore Seria oil field, located in Brunei and operated by Brunei Shell Petroleum Co. (BSP), was discovered in 1929 and has produced over 1.1 billion barrels of oil. The field still has a large Near Field Exploration (NFE) portfolio of undeveloped hydrocarbon resources in reservoir blocks on the northern flank. These blocks, located under the shallow marine surf zone, have previously been difficult to access due to the very shallow water and shoreward dipping nature of the fault blocks. However, the Seria North Flank (SNF) project has begun to unlock these volumes through the implementation of the revolutionary fish-hook well technology concept, allowing these opportunities to be developed from land. Since 2008, in order to arrest production decline and, with the fish-hook well concept in mind, a number of other opportunities along the coast were identified. An integrated exploration and development team, utilising a fit-for-purpose screening and evaluation approach, took a number of these opportunities into an integrated exploration and early production project, going from inception to project sanction in 16 months. The drilling campaign started 1 month after sanction in mid 2010. To date, 8 wells have been drilled resulting in 7 commercial discoveries. These wells have been completed and immediately put onto production, into existing infrastructure. There is now over 5 years of string activity planned, targeting the continued exploration and development of these blocks on the northern flank of the Seria field. There remains significant NFE potential 80 years on from discovery! Copyright 2011, International Petroleum Technology Conference.

Yong I.,Brunei Shell Petroleum Co.
Society of Petroleum Engineers - SPE Intelligent Energy International 2012 | Year: 2012

Brunei Shell Petroleum (BSP) first started completing Smart Wells in 1999, trialing standalone technologies such as permanent downhole gauges and inflow control valves in individual wells. Once these were seen as successful, the technology was used extensively on a single platform. This was later extended to application in a whole field, taking advantage of refinements such as variable downhole control valves and multiphase flow metering. Learning from the successes of other oil producing fields such as Champion West and Bugan, Seria North Flank was planned and designed as a fully Smart field. Seria North Flank would be the first field to fully integrate Smart technology with Smart field processes, improving the efficiency of Well and Reservoir Management activities and accelerating reservoir understanding in order to reduce uncertainties for future development. This resulted in the development of over 120 million barrels of oil, with improved Unit Technical Costs compared to an offshore development. Copyright 2012, Society of Petroleum Engineers.

Hustedt B.,Brunei Shell Petroleum Co. | Snippe J.R.,Royal Dutch Shell | Snippe J.R.,Leiden University
SPE Reservoir Evaluation and Engineering | Year: 2010

The performance of many waterfloods [and enhanced-oil-recovery (EOR) schemes] is characterized by fluid injection under fracturing conditions. Especially when the geology is complex and the mobility of the reservoir is low, induced fractures can be of the same order as the well spacing, which has a significant (in general undesired) impact on both areal sweep and vertical conformance. Therefore, fluid injection needs to be actively managed and surveyed in order to design an appropriate injection strategy over time. We have analyzed historical injection/production-test, injection step-rate-test, and falloff (FO) test (FOT) data of an existing complex waterflood in the Pierce field, North Sea. The mental subsurface model that emerged from this data analysis was developed further through a series of dynamic fracture-propagation simulations. While the data analysis was a relatively standard procedure, the fracture-modeling part was far from trivial and included simulations using a standalone fracture modeling tool and a more sophisticated coupled dynamic fracture-propagation reservoir simulator, both being in-house software tools. The combined analysis was used to develop a better understanding of the waterflood performance. The main improvement compared to previous work was the integration of the data analysis and the dynamic modeling work rather than looking at each data source individually. In combination, a consistent explanation of the observed reservoir behavior was achieved. This has resulted in changes in the day-to-day water injection management and is expected to play a key role in longer-term development strategies. Copyright © 2010 Society of Petroleum Engineers.

Langhi L.,CSIRO | Zhang Y.,CSIRO | Gartrell A.,CSIRO | Gartrell A.,Brunei Shell Petroleum Co. | And 2 more authors.
AAPG Bulletin | Year: 2010

Three-dimensional (3-D) coupled deformation and fluid-flow numerical modeling are used to simulate the response of a relatively complex set of trap-bounding faults to extensional reactivation and to investigate hydrocarbon preservation risk for structural traps in the offshore Bonaparte Basin (Laminaria High, the Timor Sea, Australian North West Shelf). The model results show that the distributions of shear strain and dilation as well as fluid flux are heterogeneous along fault planes inferring lateral variability of fault seal effectiveness. The distribution of high shear strain is seen as the main control on structural permeability and is primarily influenced by the structural architecture. Prereactivation fault size and distribution within the modeled fault population as well as fault corrugations driven by growth processes represent key elements driving the partitioning of strain and up-fault fluid flow. These factors are critical in determining oil preservation during the late reactivation phase on the Laminaria High. Testing of the model against leakage indicators defined on 3-D seismic data correlates with the numerical prediction of fault seal effectiveness and explains the complex distribution of paleo- and preserved oil columns in the study area. Copyright © 2010. The American Association of Petroleum Geologists. All rights reserved.

ten Kroode F.,Royal Dutch Shell | Bergler S.,Brunei Shell Petroleum Co. | Corsten C.,Royal Dutch Shell | de Maag J.W.,Royal Dutch Shell | And 2 more authors.
Geophysics | Year: 2013

We considered the importance of low frequencies in seismic reflection data for enhanced resolution, better penetration, and waveform and impedance inversion. We reviewed various theoretical arguments underlining why adding low frequencies may be beneficial and provided experimental evidence for the improvements by several case studies with recently acquired broadband data. We discussed where research and development efforts in the industry with respect to low frequencies should be focusing. © 2013 Society of Exploration Geophysicists.

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