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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13162, ’Samarang Field - Seismic-to-Simulation Redevelopment Evaluation Brings New Life to an Old Oil Field, Offshore Sabah, Malaysia,’ by J.K. Forrest, SPE, Schlumberger; A. Hussain, SPE, and M. Orozco, SPE, Petronas Carigali Shd. Bhd.; and J.P. Bourge, SPE, T. Bui, SPE, R. Henson, SPE, and J. Jalaludin, SPE, Schlumberger, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed. The Samarang field is offshore Sabah, East Malaysia, approximately 45 miles northwest of the Labuan gas terminal. The field surrounds a shallow reef with a water depth of 30 ft. Shell was the initial operator and relinquished the concession to Petronas Carigali Sdn. Bhd. (PCSB) in April 1995. Field-Development History Fig. 1 summarizes the production and development history of the field. The field was developed in phases, with the initial phase including the larger A and B drilling platforms; separate producing platforms at A, B, and C; and well jackets at C, D, and E. Subsequent development included well jackets at F and G. An additional well jacket, H, was planned by Shell for the east-flank development but was not implemented in 1986 because of low reserves potential and low oil prices. Formation Evaluation and Characterization A 1984 3D-seismic survey is available and was interpreted, but the best data and control are provided by the openhole logs from 144 wells. Within the field, log correlation is good in general. All of the producing reservoirs in the field are normally pressured, and the field has a normal temperature gradient for the area of approximately 1.05°/100 ft. The cored interval comprises three main facies types (i.e., sandstones, heterolithic sandstones, and shales). These facies types then were subclassified into nine lithofacies to cover the broad spectrum of sand/shale content, primary sedimentary structures, intensity of bioturbation, and unique sedimentologic character that was identified and described from the core. The ninth lithofacies in the cored intervals represents the presence of carbonates in the form of patchy carbonate cement, broken/intact shell hash layers, dolomite patches, and layered or nodular siderites. This last lithofacies, though negligible in occurrence in the whole cored section (0.4% of the total cored interval), was important as a local vertical-flow baffle. Following the identification of these lithofacies, geologists used a neural-network procedure to extend the lithofacies to most of the noncored wells. Some of the wells had wellbore problems including missing logs or cork-screwed boreholes, which did not allow their inclusion in this work. But in all cases, there was sufficient well coverage to allow the estimation of lithofacies throughout the reservoir sequences. The final neural-network model involved used the sand, silt, and clay volumes for each individual well as calculated by petrophysical methods.
- Asia > Malaysia > Sabah > South China Sea (0.82)
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- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Techbits SPE highlighted the importance of maximizing production during economic downturns at the Applied Technology Workshop “Production Enhancement—Maximizing Production and Recovery in a Challenging Economic Climate.” The workshop, held in Penang, Malaysia in October 2009, brought together an international group of 91 participants to discuss and challenge the use of production-enhancement technologies. The first keynote address by Ramlan Malek, vice president, E&P, Petronas discussed the importance of production-enhancement technologies such as improved-oil-recovery and enhanced-oil-recovery strategies in improving Malaysia’s recovery factor from the current 34–35% to more than 40%. His talk also addressed effective marginal-field development to increase and prolong peak production in Malaysia. A second keynote address by Golden Energy Chief Executive Officer Mark Pearson discussed the role of engineers and practitioners in evaluating, applying, and benchmarking production-enhancement technologies. He also provided a historical perspective of the growth of hydraulic-fracturing technologies in the US for developing its abundant tight gas plays. He believes there is a revolution in hydraulic technologies led by multizone, staged fracturing; slickwater fracturing; and horizontal-well fracturing. These—together with the integration of microseismic mapping, reservoir visualization, and fracture-design models—are enabling technologies in the US unconventional-reservoir hydrocarbon development. Assessing Business Value Petronas’ Supply Chain Manager En. Suhaimi Yasin opened the first technical session with a discussion on strategies to address the new reality of lower hydrocarbon prices without a commensurate drop in costs for rigs and services. This market dynamic has caused Petronas to re-evaluate strategies to manage cost and value. Initiatives being adopted include strategic alliances on a risk/reward basis, longer-term contracts on a partner-ship basis, e-procurement, and better leveraging of technology. Oddbjorn Skilbrei of Shell EPA discussed Lean Management Principles employed in Shell Malaysia assets to achieve breakthrough performance. The use of Lean Management Techniques has resulted in improved recognition of event triggers in well performance and reduced cycle time to fix the events. The group discussion emphasized the importance of accurate data gathering and team communication. Feroney Serbini of Schlumberger closed the session with a case study on integrating surface network modeling with a reservoir model. The study benchmarked proposed solutions against the unconstrained model, and the selected solution provided a production increase of 1 million bbl more than the second best solution. The ensuing discussion focused on gaining further insight on the modeling methodology.
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- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract A unique integrated borehole seismic technique was used to access and mitigate drilling risk on a Petronas Carigali highpressure, high-temperature (HPHT) exploration well offshore Sabah. The approach combined wireline vertical seismic profiling (VSP) and logging-while-drilling (LWD) seismic surveys to look ahead for pore-pressure prediction, geostopping, and obtaining high-resolution seismic imaging below the well path. Three wireline VSP runs and one seismic-while-drilling run were made. The first-run rig-source VSP at the 13 3/8-in. section was used to obtain an initial velocity model and early prediction ahead of bit and imaging. This was followed by a wireline vertical incident VSP (VIVSP) run at the 9 5/8-in. section to refine the pore pressure prediction and for target illumination. LWD seismic was deployed while drilling the following 8 3/8-in. section to provide real-time checkshots for pore-pressure constraint and geostopping above a key formation top to set casing. Both the wireline and LWD VIVSP showed minor faults that were not apparent on the 3D surface seismic; these faults explain the unusual kick encountered. This high-resolution image was used to decide the sidetrack path. The final rig-source VSP was logged at total depth (TD) to complement the pore-pressure prediction and seismic imaging. In addition, the real-time checkshots while drilling aided in stopping drilling to within a stand (less than 30 m) above the key formation top. The depth uncertainty of the key formation was over 130 m prior to drilling. Introduction Integrating wireline and LWD borehole seismic information for drilling is a new technique in Malaysia, first applied by PETRONAS Carigali Sdn Bhd, a subsidiary of PETRONAS. In this novel approach, we will demonstrate how borehole seismic data, which is conventionally used for geologic and geophysical interpretation, has added value for drilling and well planning. The PETRONAS well, drilled in 2008, is located off the coast of Sabah, East Malaysia. The target reservoir, in contrast to most other reservoirs in the region, is deeper, hotter, and at much higher pressures than normal. Pore pressure ramps and depleted sands in the field had previously made drilling difficult, generating hazardous incidents including stuck and lost-inhole pipe, losses, and kicks. These incidents had resulted in stopping drilling prematurely of the wells at great cost to PETRONAS, and also left the ultradeep targets unexplored. Studies by the PETRONAS sedimentologist suggested that this overpressure hazard is associated with undercompacted bathyal mudstone, and the well casing design required accurate prediction. The well path was designed to avoid the regional fault that could complicate pore-pressure prediction. Existing surface seismic and distant well-based velocity control was inadequate for this purpose.
- Asia > Malaysia (1.00)
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- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Government > Regional Government > Asia Government > Malaysia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Conclusions CSEM data is sensitive to any potential change in resistivity in the subsurface, primarily if the resistivity anomaly is the effect of a hydrocarbon accumulation. This property has been utilized to enhance exploration success in the deepwater Borneo basin. However, it is shown through the case studies that not every CSEM anomaly is created equal, and that other background rock properties such as the presence of hydrates and background resistivity can and will contribute to a potential false CSEM anomaly. Having said this, the use of the CSEM technology as part of the suite of exploration tools for prospect evaluation and derisking is still practical, but it will then require the proper integration and evaluation of all geological and geophysical data available. This integration will be essential to build a confident CSEM interpretation that will impact key decisions in the continuing efforts to explore in this basin. Acknowledgement We will like to acknowledge PETRONAS, our partners PETRONAS Carigali and ConocoPhillips for their support of this work and paper. We will also wish to acknowledge our Shell International Exploration and Production colleagues, especially Mark Rosenquist and Jeffrey Johnson for their technical support, advice and comments. Lastly, we are also grateful for the assistance and support given by fellow explorers in Sarawak Shell Berhad's deepwater exploration team.
- Geophysics > Electromagnetic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.72)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.45)
Application of Critical Technologies Enabling Low Cost Development of Thin-Bedded Heterogeneous Gas Reservoirs in the Mature North Malay Basin
Alessio, Laurent Didier (CSMP - Shell) | Howells, Christopher (CSMP) | Aboel-Abbas, Sabry Abdel Mawla | Wade, Bruce Jerome | Chu, Joanne Lai-Jean (Shell Malaysia) | Ball, Stephen Farley (CS Murtiara Petroleum Sdn Bhd)
Abstract CS Mutiara Petroleum is a Petronas Carigali - Shell Malaysia joint operating company formed in 2001, operating since then the PM301 and PM302 exploration PSCs. The company enjoyed a 100% exploration success rate in the North Malay basin, and is now rapidly transitioning into a development venture. A total of six discoveries were made since 2002 within the PM301 block. The nature of these discoveries: modest size, stacked pay, fluvio-marine transitional geological setting, high heterogeneity, partially sub-seismic resolution, creates a range of technical and economical challenges. The application of a number of specific technologies, notably to reservoir characterization are seen key to unlock the potential of these discovered volumes. Technically, in the early stages, the seismic attribute-based prediction of gas sand, using a simultaneous inversion technique, was the key enabler for exploration success, allowing to map the presence of coal versus water and gas sands. Now, success through the development phase requires the application of the following technologies:Neural-net based seismic facies, aimed at resolving lateral heterogeneity at field scale and improving the understanding of the ranges of drainage areas for development wells Low resistivity pay analysis, geared towards understanding of both static (saturation, net-to-gross) and dynamic (permeability) parameters Multiple realisation 3D modelling, using stochastic simulation, guided by techniques borrowed from Experimental Design. In addition to technical challenges, critical to unlocking these volumes is the economical optimisation of the cluster development, within a consistent portfolio management framework. This is done by using modelling at various levels: 3D modelling at field level, testing different geological concepts and the associated key uncertainties; those are then scaled up into an integrated surface-subsurface nodal network model to optimise the development of the discoveries as well as the near field potential remaining prospects. Introduction CS Mutiara Petroleum is a Petronas Carigali - Shell Malaysia joint operating company formed in 2001, operating since then the PM301 and PM302 exploration PSCs. The company has enjoyed so far a 100% exploration success rate in the North Malay basin, with a total of eight discoveries, six of which in PM301, and is now rapidly transitioning into a development venture. Block PM301 and PM302 are located in the Northern-most part of the Peninsular Malaysia acreage, just south of the Malaysia-Thailand joint development area (MTJDA) as shown on Figure 1. Geologically the acreage covered by PM301 may be divided into three zones; the Basin Centre, Hinge Line and Platform/Southwest Flank areas (Figure 2). Distinct plays exists within each area and a total of fifteen exploration/appraisal wells have been drilled by various operators; mostly in the Basin Centre where the core of the PM301 development sits, one in the Hinge Line and two on the Platform area, testing all three play areas. CSMP has drilled to date eight wells in PM301, discovering and appraising six discoveries: B. Melati, B. Kamelia, B. Anggerik, B. Zetung, Bumi South, and B. Kesumba.
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (1.00)
- Asia > Malaysia > South China Sea (0.81)
- Geology > Geological Subdiscipline (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.45)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract PETRONAS has been actively acquiring large volumes of seismic data in varied and difficult terrain to support its worldwide exploration, development and production activities. In the Malay Basin of Malaysia, the challenge begins with imaging complex stratigraphic reservoirs that are often below conventional seismic resolution. The Malay Basin being a fairly matured exploration & production province also poses another challenge, i.e. acquiring high quality seismic data around platforms and other obstructions. In Vietnam, our team was tasked with imaging complex fractured basement reservoirs under an overburden of clastic and volcanic rocks while in Indonesia, obtaining high quality, contiguous data over a land-marine interface required four different acquisition techniques and special processing workflows. In offshore Mozambique, East Africa where strong currents prevail in a N-S direction, binning and stacking methodology was used to ensure a thorough reflection of the subsurface. The high elevation changes in the mountainous region of Yemen called for a special array design, dual elevation and hybridstatic routines, while under the dunes of Algeria, the low relief structures needed proper accounting of static variation through modeling. This paper outlines the various technical challenges faced in the above regions and the solutions that were designed for them. While specific solutions are required in special circumstances, PETRONAS underlying objective is to acquire optimal data that will last the life cycle of a field where the surveys form the base cases for eventual reservoir monitoring through 4D seismics. Imaging through gas clouds, detection of fractures and improving resolution of thin pay sands and seals are some of our continuing challenges. With strong focus on proactive resolution of technical issues, the operational challenge of striking the right balance between quality, cost and efficiency is managed. Health and safety and preservation of the environment during seismic operations remain as an underlying principle of PETRONAS.
- Asia > Malaysia > South China Sea (0.50)
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- Geology > Geological Subdiscipline > Volcanology (0.59)
- Geology > Geological Subdiscipline > Stratigraphy (0.59)
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Abstract Nine gas fields have been discoved in Block B-17 in the Malaysia-Thailand Joint Devepment Area (MTJDA). Most of them have high CO2 content which makes the gas unmarketable. To achieve the commerciality, CO2 content needs to be reduce to the level that the existing market is able to accept the Block B-17 gas. Under the GSA-HOA which had been signed in 1999 between Buyers and Sellers, it had specified the CO2 content not more than 23 mole%. Therefore, the Sellers need to design the gas processing facilities to meet the requirement of Buyers. Generally, the value of sales gas is based on its heating value, not volume. The high CO2 content means the less heating value resulting the less revenue. Therefore, the Sellers must reduce the CO2 content in sales gas as low as possible. Paradoxically, the more removal of CO2 content in sales gas does not indicate the best economic results, due to the high investment cost. To optimise the project economic, the percentage of CO2 content has to define under the specification of GSA-HOA and economical consideration of the project. Several factors, for instance, gas compositions, reserves, well deliverability, need to be taken into the account of the processing design. In order to achieve the maximum benefit, the CO2 removal optimisation has to be properly designed. This paper will present a model which describes the relationship between values of sales gas and the CO2 removal cost resulting in i) good economical regime with available raw gas quality in the Joint Development Area (JDA), and ii) raw gas mixture for optimum sales gas heating value which relates to economic design of the CO2 removal. Introduction The JDA is an offshore continental shelf area in the lower Gulf of Thailand claimed by both Malaysia and Thailand (Fig. 1). The Malaysian and Thai Governments have realized that it is in the best interest of the two countries to exploit the resources in the overlapping area through mutual cooperation. Therefore, both Governments agreed on the establishment of the Malaysia-Thailand Joint Authority (MTJA) to jointly administer resources development in the JDA. MTJA awarded the Production Sharing Contract in Block A-18 to Triton Oil Company of Thailand and Petronas Carigali (JDA) Sdn. Bhd. and Block B-17&C19 to PTTEP International Limited and Petronas Carigali (JDA) Sdn. Bhd. Triton Oil Company of Thailand and Petronas Carigali (JDA) Sdn. Bhd. established an operating company, namely Carigali-Triton Operating Company Sdn. Bhd. (CTOC), for petroleum operations in Block A-18 while PTTEP International Limited and Petronas Carigali (JDA) Sdn. Bhd. established Carigali-PTTEPI Operating Company Sdn. Bhd. to operate petroleum activities in Block B-17&C-19. Since the signing of the PSCs in April 1994, a total of 5,800 line km of 2D seismic data and 1,166 square km. of 3D seismic data was acquired and interpreted by CTOC in Block A-18. For Blocks B-17 & C-19, CPOC also acquired a total of 6,100 lines km of 2D seismic data and 1,938 square km of 3D seismic data. From 1994 to 2002, a total of thirty-three (33) exploration wells were drilled in the JDA: with eighteen (18) wells in Block A-18, and fifteen (15) wells in Block B-17. Eighteen (18) geological structures have been drilled and tested, resulting in eighteen (18) gas discoveries: 9 fields in Block A-18, namely, Cakerawala, Bulan, Suriya, Bumi, Bumi East, Senja, Samudra, Wira, and Samudra North fields; and 9 fields in Block B-17, namely, Muda, Tapi, Jengka, Amarit, Mali, Jengka South, Jengka West, Jengka East and Muda South fields. Some of these fields also have minor oil accumulations. Up to date, approximately 8.9 Trillion standard cubic feet (Tcf) of (Proved + Probable) gas reserves, exclusive of CO2, from eighteen (18) fields have been discovered in the JDA, 6.9 Tcf in Block A-18 and 2 Tcf in Block B-17. The amount of 2 Tcf reservres in Block B-17 which is implied to the amount of 2.76 Tcf of raw gas is challenging to develop.
- Asia > Thailand (1.00)
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- Government > Regional Government > Asia Government > Malaysia Government (0.86)
- Government > Regional Government > Asia Government > Thailand Government (0.75)
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (Gulf of Siam) > Samudra North Field > Malaysia-Thailand JDA > Block A-18 > Samudra North Field (0.98)
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (Gulf of Siam) > Muda Field > Malaysia-Thailand JDA > Block B-17 > Muda Field (0.94)
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (Gulf of Siam) > Jengka Field > Malaysia-Thailand JDA > Block B-17 > Jengka Field (0.94)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Bokor Field Redevelopment - A Brown Field Integrated Modeling Workflow Case Study
Flew, Stephen (Schlumberger) | Mulcahy, Matthew (Schlumberger) | Stelzer, Hermann (Schlumberger) | Boitel, Alain (Schlumberger) | Zainuddin, Faizal (Petronas Carigali Sdn Bhd) | Harun, Abd Rahman (Petronas Carigali Sdn Bhd) | Hassan, Zulkarnain (Petronas Carigali Sdn Bhd) | Aziz, Kamaroll Zaman A. (Petronas Carigali Sdn Bhd)
Abstract After more than 20 years of production, the 800 million STB Bokor field, offshore Sarawak, Malaysia, is set to undergo a revitalization to increase production rates and recovery factors. A joint PETRONAS Carigali (PCSB)-Schlumberger team was formed to review the field and develop the first full field simulation model, which will be utilized as a ‘live’ model for identifying further potential and for future reviews. This paper outlines the modeling workflow and processes developed to allow the study to be completed within a shorter duration than with a conventional approach, as well as the key study results. Made up of some 130 vertically stacked reservoirs over a 6,000-ft interval, evaluation of the field is hampered by the lack of any useful seismic images over the hydrocarbon zone, owing to shallow gas and other anomalies. Understanding the reservoir behaviour has always been a challenge, with the degree of sand consolidation in the reservoirs varying from totally unconsolidated at 1,500 ft subsea, filled with 10 cP oil, to consolidated deeper sands, with 0.1 cP oil at 7,500 ft subsea. In addition, the limited pressure depletion owing to the presence of a very strong aquifer, and the fact that many fluid contacts have not been penetrated, means that significant uncertainty still exists over the likely stock-tank oil initially in place (STOIIP). By fully utilising all available data and an iterative team-based approach to history-matching the geostatistical models with production data, an understanding of the key parameters was gained. This revealed that in many reservoirs, what was previously considered poor-quality rock was in fact a major contributor to reservoir flow, being neither as poor in permeability nor as high in water saturation as previous interpretations suggested. Through the increased understanding gained during the review, robust predictions have allowed new facilities to be appropriately sized, allowing the field to begin its new lease of life. Introduction Many of the challenges to redeveloping the Bokor field are related to continuing uncertainty about the initial oil in place (OIP). As detailed elsewhere, the estimation of the STOIIP has more than tripled since the original decision to develop was taken. Even with the extensive well penetrations and production period, significant uncertainty still remains because of the existence of a shallow gas cloud (Fig. 1) that masks much of the faulted crestal area, especially in the deeper intervals in which the seismic imaging is particularly poor (Fig. 2). In addition to the uncertainty in bulk volume, the extensive vertical interval (more than 130 reservoirs between 1,500 and 7,500 ft subsea) and limited flank wells means that for many sands no initial fluid contact was established. These factors result in a wide band of uncertainty on remaining OIP, with substantial upside potential, especially in the deeper sands. Add to these structural issues a 12-month project time frame, severe hole washout in many sands, internal gravel packs making individual sand offtake determination difficult, a low gas/oil ratio (GOR), high-viscosity oil, and a very strong aquifer, and the complexity of the task becomes clear. Whilst a few individual reservoir models have been built over the field life to review sweep and infill locations, no full field model had been constructed previously. Production forecasts were the result of decline curve analyses and were therefore not readily updatable with any change in operating conditions such as increased lift gas injection. Therefore, a key deliverable was a full field reservoir model within which various redevelopment scenarios could be considered before any major capital expenditures are finalised.
- North America > United States > Texas (1.00)
- Asia > Malaysia > Sarawak > South China Sea (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.34)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
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Guntong - Key Challenges and Issues in the Management of a Large Complex Oil Field
Wan-Nawawi, Wan-Mohamad (ExxonMobil Exploration and Production Malaysia Inc.) | Coyne, Patrick L. (ExxonMobil Exploration and Production Malaysia Inc.) | Hinton, Paul V. (ExxonMobil Exploration and Production Malaysia Inc.) | Razalli, Razmahwata M. (ExxonMobil Exploration and Production Malaysia Inc.)
Abstract The Guntong field is currently the largest waterflood field and a major oil producer in Peninsula Malaysia. The field and its development are highly complex, resulting in various challenges in the areas of reservoir description, reservoir management, and facilities optimization. This paper showcases key challenges and the evolution of the field depletion plan as the complexities were identified and better defined. Based on actual performance, and updated geoscience and reservoir engineering studies, various changes to the original depletion plan are being implemented even after 17 years of production. The changes range from a revision in waterflood operating pressure strategy, to innovative facilities optimization, and the more expensive workovers and infill drilling,. Effective teamwork by multi disciplinary team members also played a major role in transforming the challenges into opportunities. The implemented changes to-date have successfully increased production and reserves. Introduction The Guntong field is a large anticline of about 12 km long and 7km wide, located 210km offshore Terengganu, Malaysia (Fig. 1). It was discovered in 1978 and a total of 9 exploration wells were drilled. Two major north-south trending faults divide it into three fault blocks; East, Central, and West. Field development started in 1985 and a total of 138 development wells have been drilled through 1997. ExxonMobil Exploration and Production Malaysia Inc. operates the field in partnership with PETRONAS Carigali Sdn Bhd, as Production Sharing Contract (PSC) contractors to PETRONAS, the national oil company of Malaysia. The first 3D seismic survey was acquired in 1985 and was extensively used to formulate and enhance the original field development plan. A newer 3D seismic survey was acquired in 1998 and fieldwide geologic studies were recently completed which integrate the seismic data, sequence stratigraphy, improved formation evaluation, and performance data. Reservoir Description Hydrocarbon-bearing reservoirs are primarily mid-Miocene sandstones deposited in fluvial/tidal/deltaic environments. There are fifteen vertically stacked, highly heterogeneous reservoirs, cut by numerous channels and faults. As depicted by the cross-section (Fig. 3), these reservoirs have variable reservoir thickness, quality, areal extent, gas cap size, fluid contacts, and oil column thickness. The main reservoirs are in the group I sandstones, sub-divided into the Upper I group consisting of the I-10 through I-45 reservoirs, and the Lower I group which is made up of the I-60 through I-104 reservoirs.The major reservoirs are the I-10, I-25, and I-70, containing close to 75% of the total field recoverable reserves. Reservoir quality varies significantly. An example is the contrast between the clean I-25, which consists largely of fluvial deposits and the more stratified I-10, which is mainly subtidal and intertidal deposits (Fig. 3) Also present are the group J reservoirs, which are generally of poorer quality with thinner oil columns. However, this paper focuses on the group I reservoirs, and primarily the I-10 and I-25 reservoirs.
- North America > United States > Texas (0.69)
- Asia > Malaysia > Terengganu > South China Sea (0.56)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.74)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Tidal Flat Environment (0.54)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.45)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Guntong Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 31 > Palas Field (0.98)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
Abstract In order to meet the challenge faced by PETRONAS Carigali's recent accelerated growth, an Integrated Technology Solution (ITS) was developed to optimise and stream-line key business elements of data, process, technology and people development. The Data Ownership and Management initiative emphasized on the project team members' ownership of the data as key corporate assets and set the proper policies and procedures for handling, storing and retrieval of data and information. The Process Optimisation initiative, delivered an optimised and collaborative road map for the project team to select the optimum route to produce the Field Development Plan (FDP), while defining standards for the deliverables, milestones for validation and peer reviews. The Technology Mastery initiative provided a framework for a structured and self-driven development of the project team members. This ITS program is a step forward towards a knowledge enabled learning organisation where skilled knowledge workers use readily available, clean and validated data and information, through optimised and collaborative processes that leverage on state-of-the-art technologies to increase hydrocarbon reserves and company profitability. Introduction In recent years PETRONAS Carigali Sdn Bhd (PCSB) experienced an accelerated growth that stretched its existing resources and challenged its Field Development Planning's business ingredients, namely the data, workflow processes, technology and people. At the dawn of the 21st century a new capability program was launched in PCSB to adopt a comprehensive approach to address the issues facing its Field Development Planning (FDP)'s key business ingredient in an integrated manner, as the spring board enabling PCSB to meet its current day challenges against a backdrop of rapid changes and leaps in technology advancements. Data, processes and tools are inter-linked through people, the heart and soul of the organisation. That is why the Integrated Technology Solution (ITS) has people as its primary focus (Fig.1). By providing them with easily accessible data to work with, on-the-job training on existing tools and applications, and optimised workflow and processes that would help them function better as a team and be able to produce best in class results. The focus during the first year of this fully in-house program are the Geoscience (Geology & Geophysics) and Petroleum Engineering (Formation Evaluation) skill group, the domain of the Petroleum Engineering Department of PCSB. This paper describes how the first phase of the program was implemented, the benefits obtained, the lessons learned and the plans for the future. The initiative was developed, managed, and piloted by a joint PCSB-GeoQuest team, leveraging on and integrating existing PCSB internal expertise, tools, and capability within the domains of Information Technology, Data Management, Human Resource Development, Technology and Quality. The initiative was officially launched on August 18, 1999. Data ownership and management Objective. The data ownership and management initiative's objective is to design and implement the foundation of data and information management system that best fit the business requirements. It focused on building a solid foundation of clean, organised, validated data and making this data readily accessable to the team to work. This could only be achieved if the project teams take ownership of the data and treat it as the company 's most important asset.
- Overview (0.56)
- Instructional Material (0.47)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.47)
- Geophysics > Seismic Surveying > Seismic Processing (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.45)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)