PGCE 2004

The Tangga Barat field discovered in 1985 by Esso Production Malaysia Inc well Tangga Barat-1A is one of a series of Middle Miocene Gas Fields aligned along the axis of the Malay Basin offshore Peninsula Malaysia. The reservoirs of this Greenfield range in age from mid Middle Miocene H Group shallow-marine sands, through the fluvial-deltaic dominated E Group, to the early Upper Miocene D Group neritic sands. The primary reserves of the Tangga Barat field are contained within the E Group reservoirs that contain circa eighty percent of the hydrocarbons in place. However, a relatively high degree of uncertainty is inherent in the subsurface understanding as a result of both the low density of well coverage and due to gasshadow effects immediately overlying the field that degrades the seismic image of the reservoirs. This paper focuses on the attempt to quantify the subsurface uncertainty by the construction of a 3D Geological Model utilising the results of the interpretation of a recently acquired 3D seismic survey and integrated with all log, engineering and drilling data. The paper also summarises the impact of the model on the Field Development Plan for Tangga Barat.

The eastern Sabah area has undergone several deformational phases. The latest is the Pliocene-Pleistocene deformation, with the maximum stress in NNW direction. This deformation was responsible for shaping the present day landscape of eastern Sabah and also responsible for reactivation of old structures and the formation of latest structures that exist today. In the offshore area, the structures that have been drilled for hydrocarbon are mostly faulted anticlines formed by a combination of wrenching and syn-sedimentary growth-faulting. The hydrocarbon has been discovered in middle to upper Miocene sand, which is equivalent to the onshore SegamalTanjong formations and the Dent Group. This indicates the existence of an active petroleum system is operating in the area. This is also corroborated by the presences of hydrocarbon seeps in the onshore area. The similar structural style is also observed in the onshore eastern Sabah. From structural interpretation of SAR images, it is found that the area is dominated by strike-slip regional faults trending in NE-SW, NW-SE and NNW-SSE. The observed structural grains along the faults indicate wrench movement, which may favor the formation of hydrocarbon traps. There are several types of structures associated with these faults, that are of interest to petroleum exploration such as en echelon drag folds and fault bounded anticlines. Most of these wrench related structures and a few others are common in this area. The outcrops of the Dent Peninsula, eastern Sabah is the uplifted portion of the strata forming the Sandakan sub-basin, which collectively known as the Dent Group. It comprises the Sebahat, Ganduman and Togopi formations, which ranges from middle Miocene to Pleistocene. The succession has been interpreted as a prograding delta, with the Sebahat being the prodelta and marine facies, overlain by the coastal and deltaic Ganduman formation forming the top-set. The Togopi is unconformable upon the underlying formations, marking a major tectonic event in the Late Miocene to Pliocene. The unconformity below the Togopi formation has been interpreted as a major sequence boundary in eastern Sabah. It has been a significant sealing layer for hydrocarbon in the offshore area, where most of the discovered hydrocarbon is trapped by this unconformity. Since its coverage extend into the onshore area, it is possible to find hydrocarbon trapped in the structures below it.

The Kinabalu field is located offshore Sabah, 55 km KM WNW of Labuan Island. The field was discovered in 1989 by well KN- 1, which found several stacked Late Miocene reservoirs. The reservoirs are late Miocene sediments deposited in the upper to lower shoreface environments. The hydrocarbon accumulation occurs in a 3-way dip closure monocline in the hanging wall of a SW-NE trending growth normal fault. The Kinabalu field consists of is made of three accumulations, the Main, the Deep and the East, that contain 500 mmstb STOIIP. The STOIIP of the field is 500 MMstb, 80% of of which is oil in place located in the Main accumulation. Development of the Kinabalu field started in 1997 with development drilling of the Main accumulations. First oil was in December 1997. Historically the reservoirs in the Main accumulations were modelled individually owing to . This approach was followed because of limitations in computing power and because modelling packages at that the time could not handle listric dipping faults. Static and dynamic modelling were challenging since multiple models needed frequent updates had to be updated all the time which require extensive staff and computer time. This required lot of man power and consumed lot of time. Well planning using multiple single models was another challenge since a typical well in Kinabalu wells typically have has several targets. Also In addition, use of Excel spreadsheets to reconcile reconciliation of simulation output from individual models into a full field output was done using Excel spreadsheets, which made auditing difficult almost impossible and often introduced several errors. With The significant improvements in computing power and the advances ment in modelling packages and the push by the leadership team asked for a modelling approach combining that could combine simplicity and speed. meant a To achieve a new way of doing things, had to be found. The the team, therefore, came up with the idea of a “Kinabalu Mega Model”. The Kinabalu Mega Model (i.e. KMM) incorporates all the 35 oil-bearing reservoirs in the Main accumulations, . There are 35 stacked reservoir which are modelled in KMM, covering the depth range from about 4000 to 10000 ft tvdss. The aerial dimension of the model is 25000 ft x 8000 ft. Prior to upscaling, the static model has 3 million grid cells that are . The size of each grid cell before upscaling is 300 ft x 300 ft x 4 ft. After upscaling for dynamic modelling the size of each grid cell is 300 ftx300ftx 18 ft. In terms of static modeling workflow, this new mega model enables a better handling of structural uncertainty since all the reservoirs are now share an integrated into the same structural framework. Subsequently, the sensitivity to petrophysical properties across all reservoirs in different structural realizations can be tested. The model also provides a common platform for members of subsurface team and requires fewer people to maintain the project. This contributes to time saving and better data management. process. From the dynamic point of view, the availability of the KMM has simplified and speed up history matching and forecasting. Wells with completions in multiple reservoirs can be simulated with better accuracy than previously. Planning of future development activities are now very transparent to all multi-discipline team members. Lastly, we now have a very efficient tool for full field management. In conclusion the main contributions of the Kinabalu Mega Model are summarized below: 1. Increase modelling speed, which translates into time saving.
2. A simplified and transparent modelling methodology which requires less man power, yet still retains accuracy. 3. Uncertainty ies modelling and data management are handled in a very efficient way. 4. The mega model has also given the team the holistic view when it comes to future development in Kinabalu. (The team used to look at individual parts of the field).

This paper illustrates an example of integrated multi-disciplinary approach in planning an infill well to drain the oil in the 1-10 reservoir in the Central fault Block of Guntong field. The 1-10 is one of the major reservoirs in the EMEPMI-operated Guntong Field in the Malay basin. The 1-10 consists of low to high energy tidal deposits in the form of subtidal bars and flats. The reservoir is driven mainly by water injection, with occasional gas injection updip. A 3D geologic model has been built and upscaled for simulation in 2001. The well was planned to be a very high angle well that is strata-parallel to the reservoir. The challenge was to stay within 4-5 m from the top of 1-10 for approximately 500 m to target the best part of this reservoir. The main risks associated with the
well were the location of the injected water front, the possibility and extent of gas streaking down through the high permeability layers ane reservoir quality at the heel section of the well. An integrated team consisting of geoscientists, a reservoir engineer and a drilling engineer worked closely to optimise the location and well design. Seismic impedence, AVO respose and time-lapse analysis were integrated with sequence stratigraphy, production performance data and reservoir simulation to finalize the target location and to fully describe this infill opportunity, inculding the associated risks. Several iterations and scenarios were developed to choose the best location to ensure the well is economically robust. A process chart was also developed collectively to lay down the plans while drilling, including fallback actions. Communication among the multi-disciplinary well planning team and the field personnel were also vital in ensuring that all parties were aware of the drilling plans. The well was successfully drilled in May 2004 and encountered oil in 1-10 reservoir with minor gas streaks. Total net completion length is about 400MD and the well flows at about 10000 b/d of oil.

In order for petroleum exploration activities to progress in the innovative use of the latest technology, and achieve the commendable result of ensuring more discoveries, technology must be underlain by a foundation of effective information management (Nor, 2001). The petroleum industry continues to grow as one of the largest and most intensive creators and consumers of digital data and now recognizes that an organization’s level of maturity in dealing with information and knowledge management can be measured objectively, used as a benchmark to compare with other similar organizations, and provide a proactive plan for increasing performance and profitability. A Data Management Maturity Model (DMMM ) has been proposed as a method of establishing this comparison (D’Angelo and Troy, 2000). The model analyzes organizations as they move from a base level to a fully optimized structure in which data, information, and knowledge add value at all stages in a life of field project cycle. Operations are categorized by analyzing processes, technology, consistency of results, and ability to quantify value.

This paper presents the Multiple Bischke Plot Analysis (MBPA), and forward modeling balancing techniques as powerful tools to categorize growth in complex structural regimes. The method is based on existing correlations and requires little additional interpretation effort to provide useful results. We have applied this MBPA method as well as forward modeling balancing techniques to a number of faulted structures, which have undergone both extention and compression in the Sabah and North Laconia Basins to determine the relative growth histories.

Deepwater environments typically involve an undercompacted overburden with low quality (Q) factor values (high rates of anelastic attenuation). Rugose water bottom characteristics and complex stratigraphic styles collectively yield surface seismic data that has a small frequency bandwidth and a poor signal-to-noise content. A common misconception associates shallow seismic source and streamer towing depth with increased high frequency amplitudes, larger frequency range, and larger frequency bandwidth (and hence, better vertical resolution). We demonstrate how this misconception arises, and provide a quantitative demonstrate of the true factors affecting frequency content in deepwater data. Noise attenuation is particularly difficult in deepwater areas, as out-of-the-plane (3D) noise generating mechanisms are typically abundant. Standard 2D noise filters are ineffective, thereby degrading an already restricted frequency bandwidth. Consequently, “true” 3D processing algorithms must be applied to remove all noise types. This invokes a critical requirement that the seismic wavefield is densely sampled in both the inline and cross-line shooting directions, and that specific shooting strategies are employed during the 3D acquisition experiment. Overall, we demonstrate how to optimally acquire 3D seismic data in deepwater areas, so that the maximum possible frequency bandwidth, with optimal signal-to-noise ratio, can be both acquired and imaged.

Tanjung Jabung Block seismic project, conducted onshore and offshore of Indonesian Province of Iambi, was one of the challenging seismic survey operations undertaken by Petronas Carigali. Four types of seismic methods, i.e. shallow marine streamer, land, ocean bottom cable dual component (OBC-2C) and transition zone (TZ), were deployed successively. As there were no technically qualified contractors capable of providing services for all four methods, Petronas Carigali decided to split the works into two different seismic survey contractors. While the decision to deploy multi seismic methods was a cost-effective one, it added significant technical, operation and HSE challenges. This paper describes several key challenges, issues and adopted solutions during all the above four different seismic survey methods. As TZ and OBC-2C methods utilized different types of sources and receivers, optimum data overlap was essential for the design of seismic data processing matching filter to correctly merge these two different data types. However, it was challenging task to correctly acquire this required overlap due to shallow water, high daily tide and contractor’s equipment. Harsh working conditions, private cultivated lands, busy shipping lanes, intensive fishing activities, under adaptation of locally sourced boats and lack of contractor’s advance computer QC software were few examples of project key challenges and issues. There were also environmental related challenges and issues where the local authorities prohibited any seismic survey works within the mangrove nature reserve causing no seismic data zone between land and TZ surveys. This no data zone is a challenge for our geophysicist to accurately tie seismic data between land and offshore areas. Additionally there were contract administration and procurement related challenges and issues. It was challenging task to timely administer contracts as there were seven different contracts of various specifications with several contractors. Close onsite project supervision, excellent communication among all parties, thorough project work planning and close interactions with contractor during the operations are several lessons learnt from this project. At the end, the project was successfully completed without any LTI incidents after more than 1.3 millions man-hours were recorded.

The Malay Basin, located offshore Peninsular Malaysia, is a large Tertiary basin that developed by crustal extensional and strike-slip tectonics. Subsurface pressure data from the central and northern parts of the basin reveal two major overpressure compartments: one in the basin centre and another on the basin flank. In both cases, the overpressure is sealed by laterally extensive, regional shale units. In general, the present-day depth to the top of overpressure has a convex-upward surface; shallower at the centre and gradually deepening towards the flanks. This phenomenon is found to be related to the varying sediment burial rates from basin centre to flanks; a higher sedimentfburial rate produces a shallower top of overpressure. In detail, however, the present-day depth to top of overpressure is also influenced by the presence of regional shale seals. In the basin centre, the top of overpressure is generally between 1900 and 2000 m depth and is limited stratigraphically to within the lower part of seismo-stratigraphic unit or “group” E. The top of overpressure is shallower towards the basin flanks, and is less than 1500 m deep along the faulted, western basin margin. It appears that the top of overpressure in the basin centre is influenced by the Group F shale, and that the overpressure in lower Group E down to Group F represents the overpressure transition zone. Modelling studies indicate that overpressure had developed very early, during the synrift phase (ca. 30-2 1 Ma), when sediment burial rates were very high (>1000 rn/Ma). The overpressure developed during this “build-up” phase, however, has been dissipating gradually since the post-rift phase began 21 Ma ago, when burial rates were reduced considerably below 1000 rn/Ma. This indicates that disequilibrium compaction, resulting from high sediment burial rates, was effective only during the synrift phase of basin development. Low sediment burial rates during the post-rift phase (generally less than 500 rn/Ma) are not enough for overpressure to develop. Hence, the overpressure in the post-rift strata, as observed at the presentday, appears to be of secondary origin, derived from the excess pressure in the underlying synrift strata. The present-day distribution of overpressure in the basin, therefore, is not a primary feature, but is due to pressure dissipation and re-distribution during the post-rift phase of basin evolution.

The Semangkok Field, located offshore Peninsular Malaysia was first discovered in 1981 and developed in 1984 by two platforms, Semangkok A and B through 41 development wells. Subsequent to the initial field development, EMEPMI has conducted several re-developments at Semangkok, including the Semangkok B infill drilling program in 2001, and Semangkok A infill drilling program in 2003. This paper addresses the challenges involved in the re-development of one such reservoir, the E-20, which has a relatively
thin (—1 2m) oil column at Semangkok. The E-20 reservoir, with its —12 m crestal oil column, small gas cap and strong bottom water drive, was considered uneconomic during the initial development. Three wells were completed in this reservoir as a secondary objective during the initial development, with only one well making reasonable cumulative production of 0.5 MBO, while the other two wells saw early water breakthrough. All of the wells had relatively long perforation intervals, with the higher cumulative well having a coal layer close to the base of perforation which potentially acted as a buffer to prevent early water encroachment. In 2002, an idle well was worked-over to add perforation in the E-20 reservoir. The perforated interval was only 1m TVD at the mid oil column, to provide sufficient stand-off from the interpreted current OWC and help reduce early water breakthrough. This well produced at a sustainable rate of 0.8 kbd with low GOR and watercut, and based on the encouraging performance, two additional single horizontal oil producing well targets were recognized for future development. Key challenges for these targets included the optimal placement of the horizontal section to minimize water coning and maximize productivity of the thin oil column. As such, risks for these wells included structural and stratigraphic uncertainties and the possibility of early water breakthrough. This paper discusses ways the integrated team took to optimally address these challenges and maximize production.