Proper and reliable resource assessment of hydrocarbons in-place and recoverable volumes is one of the key factors in field development planning (FDP) and determines the commitments made to the host government for the reserves to be developed (RTBD). Many times, it is critical to update the resources and reserves of a producing asset through full field reviews (FFR) to gauge the production attainment and success of initial forecasts in FDP and also to locate any upside/locked-in potential.
Often uncertainties in the field development are expected to reduce as the field produces, but in many cases the results show otherwise due to lack/ inaccuracy of data or existing reservoir complexities. This paper elaborates how an integrated approach utilizing analytical methods (material balance, pressure and rate transient analysis) combined to numerical reservoir simulation is used for accurate resource assessment of an over-pressured gas condensate reservoir that suffers from lack of geological and petrophysical data, faulty production data measurement system and complex fluid and pressure behavior.
A comprehensive workflow comprising of different methodologies is used to harness the available geological, petrophysical, production and pressure data. Over-pressured and compressibility corrected gas material balance and pressure and rate transient analysis (RTA) are conducted using static and flowing data to encompass the existing uncertainties on resource numbers and generate low, base and high cases. The results of these methods are then successfully utilized to construct the dynamic reservoir model for evaluation of the upside and near field exploitation (NFE) potential. The results of the full field review lead to a 50% increase in the gas initially in-place compared to FDP volumes and a significant addition in the proven reserve. This increase in volumes was investigated through proactive surveillance for a period of time and was well supported by the reservoir and well performance.
A novel approach to numerically model the over-pressured gas reservoirs is developed using a simple concept of compressibility modifications supported by production data history match and analogue core data. The results of the study greatly benefited the production sharing contract (PSC) and lead to production enhancement from the field through a proper debottlenecking project.
Bashir, Yasir (Universiti Teknologi PETRONAS) | Babasafari, Amir Abbas (Universiti Teknologi PETRONAS) | Biswas, Ajay (Universiti Teknologi PETRONAS) | Hamidi, Rositi (Universiti Teknologi PETRONAS) | Moussavi Alashloo, Seyed Yaser (Universiti Teknologi PETRONAS) | Tariq Janjuah, Hammad (American University of Beirut) | Prasad Ghosh, Deva (Universiti Teknologi PETRONAS) | Weng Sum, Chow (Universiti Teknologi PETRONAS)
A majority of remaining proven Oil & Gas reserves is contained by Carbonate reservoir, and much more complicated to explore as imaging of the Carbonate rocks is poor. In case of Carbonate data, seismic diffraction imaging has contributed to an enhancement in the quality of seismic but there is still lack of understanding the lithology and impedance contrast which can be defined by the seismic inversion. In contrast, to the conventional process, an integration of seismic inversion methods are necessary to understand the lithology and include the full band of frequency in our initial model to incorporate and detail study about the basin for prospect evaluation. In this paper, an integrated approch is developed for better deleniation of subsurface structure and lithologies. Seismic post stack inversion technique is applied to the Carbonate field to study Electroficies and lithofacies of subsurface strata for better and detail study of the reservoir.
Nik Kamaruddin, Nik M Fadhlan (Petroliam Nasional Berhad) | Teng, Kevin Ging Ern (Petroliam Nasional Berhad) | Musa, Ikhwanul Hafizi (Petroliam Nasional Berhad) | Tan, Chee Phuat (Petroliam Nasional Berhad)
This paper presents a study on the risk associated with CO2 injection in geological storage and fault reactivation through a comprehensive workflow for determining the feasibility of CO2 storage campaign in carbonate reservoir in Malaysia. The study includes constructing a 4-D coupled reservoir geomechanical model and developing a workflow that can be used to evaluate geomechanics risks associated with carbon capture and storage (CCS) by outlining results and findings that drive key decisions in the planning of CCS strategy.
The workflows aims to better delineate and enumerate the risks with CCS as it constructing and calibrating single well models by corroborating numerous inputs including stringent laboratory testing data and drilling analysis, and combining with structural model and reservoir model to create a field wide 4-D geomechanical model using advanced time lapsed geomechanics simulation. Coupled simulations with the dynamic reservoir model provided predictions of the fault stability by considering fault deformation. The paper further highlights the geomechanics evaluation consideration (economics and engineering trade-off) in designing maximum safe injection pressure for CO2 sequestration program.
The results of the study show fault condition subjected to different time-steps of the coupled simulation during depletion and injection. At each time-step, the development of plastic shear strain and absolute displacement are plotted and risks associated with the change in reservoir pressure are assessed and quantified. Different injection plans are modelled to determine the impact on final storage capacity, long term fluid containment and upper safe injection limit to avoid breaching the caprock.
The study offers the utilization of the latest techniques in 4-D coupled geomechanical modelling which reduced the study time and cost significantly, making it affordable for in-time solution for decision making. The paper also aims to encourage the consideration of the applied novel workflow involved in CCS strategye valuation focusing on risk assessment which ultimately will affect reservoir maximum safe injection limit, capacity, long term storage safety, and monitoring program to mitigate potential geohazard leakage.
Warrlich, G. M. (Sarawak Shell Bhd) | Ryba, A. (Sarawak Shell Bhd) | Adams, E. (Sarawak Shell Bhd) | Tam, T. (Sarawak Shell Bhd) | Chiew, E. C. (Sarawak Shell Bhd) | Angelatos, M. (Sarawak Shell Bhd) | Soo, D. K. (Sarawak Shell Bhd) | Lojikim, Chrissie (Sarawak Shell Bhd)
The knowledge acquired is presently used to optimize existing field recovery, develop new fields without production data and reduce geohazards for drilling operations. It also provides an outstanding data set that can be extrapolated to understand the role of reservoir heterogeneities and hydrocarbon properties on production behavior and recovery in similar fields with less data outside Luconia. This presentation focusses on how production & surveillance data can be used to characterize and quantify the impact that carbonate reservoir properties & heterogeneities have on hydrocarbon flow during production. Data used includes water contact rise & inflow logging, GPSbased subsidence and its link to reservoir porosity, and investigation of the impact of overpressure on porosity and aquifer strength.
D. Warrlich, Georg Mathis (Shell Malaysia) | Palm, Danielle (Shell Malaysia) | van Alebeek, Hans Johannes (Shell Malaysia) | Volchkov, Dmitry (Shell Malaysia) | Hong, Sia Chew (Shell Malaysia) | Adams, Erwin W (Shell Malaysia) | Ryba, Artur (Shell Malaysia) | Schutjens, Peter Maarten (Shell India Markets Private Ltd.) | Stevens, David A (Shell Malaysia) | Peacock, Anthony William (Shell Malaysia) | Row, Zuka (Shell Malaysia) | Ghosh, Kallole (Shell Malaysia)
Pore-pressure prediction in a mature hydrocarbon province with producing fields bears issues different from an exploration or immature basin setting. Appraisal and production activities can introduce an additional set of complications that needs to be considered to make well-constrained pore-pressure predictions. Problems for infill drilling can arise from severe changes in rock strength (fracture gradient reduction), caused by depletion of reservoirs through production, or development drilling in neighboring fields, if there is pressure communication via a common aquifer. Increases above initial pressure can be caused by crossflow from overpressured reservoir layers through poor cement bonds or abandonments. Reservoirs can also receive additional pressure through water or gas injection.
The Luconia gas province is a mature basin and several stages of successful exploration, appraisal, development and infill-drilling campaigns. Shell, supported by its partners, has successfully overcome the above mentioned issues by thorough and innovative pore-pressure prediction approaches. In addition to the standard bracketing of uncertainties, 3 key process elements are employed: (1) proper framing of the pore-pressure prediction and continued interfaces with all stakeholders and (2) a ‘scenario-based’ prediction approach, that captures all possible effects caused by appraisal and production of the target reservoir or neighboring fields, and that predicts their impact on the pore pressure of the reservoir to be drilled. (3) Risks identified are captured and mitigated via a 5 point pore-pressure prediction that spans a facilities design range as well as a wider drilling range. The drilling-range end members have a low probability of occurring, but have to be captured to enable hardware selection that ensures safe drilling execution. State of the art technologies are employed to achieve this, including 4D seismic, regional data bases, innovative modeling methodologies and full integration in a well-delivery process.
Jong, John (JX Nippon Oil & Gas Exploration Corp.) | Barker, Steven (JX Nippon Oil & Gas Exploration Corp.) | Kessler, Franz L. (Petrotechnical Inspection (M) Sdn. Bhd. currently Lundin Malaysia BV.) | Tran, Quoc Tan (JX Nippon Oil & Gas Exploration Corp.)
The Bunguran Trough, where the BFB (Figure 1) is formed and covers JX Nippon operated Deepwater Block 2F is located roughly in the centre of the SCS, where the national offshore areas of Indonesia, Malaysia and Vietnam converge (Figure 2). It is located between two key lineaments along which tectonic play segment boundaries in the SCS can be defined: 1. The hinge line of the Malay Basin against the Tenggol Arch and Natuna Arch, called the Lupar Line in offshore Sarawak (Figure 3a); it marks the onset of Palaeogene to Middle Miocene subsidence in the eastern half of the SCS, and 2. The Baram Line, a probable extension and/or continuation of the Red River Fault System which defines the post Middle Miocene Sundaland clastic depocentres in coastal Vietnam; curving southeastwards, then eastwards toward Sarawak where it forms the boundary between the Central Luconia carbonate platform and the Baram Delta (Figures 3a and 3b). The Cenozoic evolution of South-East Asia records a diverse array of tectonic processes with rifting, subduction, terrane collision and large-scale continental strike-slip faulting occurring in spatially and 6 IPTC-18197-MS Figure 5--IHS-derived stratigraphic correlation summary for the Malay-Penyu-Natuna and Nam Con Son Basin.
Since late 1960's, there are intensive exploration activities conducted off the coast of the state of Sarawak, Malaysia. The offshore region to the northwest of Borneo Island saw a heightened state of exploration activities for hydrocarbon following increasing demand for fossil fuel as a result of world industrialization. Miocene carbonate pinnacles are one of the target play types identified and chased within the Central Luconia geologic region. In those days the more obvious, mega size shallow carbonate build-ups which are considered as the "low laying fruits?? became the first priority exploration test candidates. Some of the pinnacle build-ups are proven gas fields with few of them classified as "giant class?? accumulations (Figure 1). Nevertheless, a lower than expected overall exploration success statistical trend coupled with low priority in the business strategy for gaseous hydrocarbon further compounded the issues which arrested the exploration initiatives. A "hiatus?? in exploration activities ensued beginning in 1980's. On the subsurface side, geologic assessments then identified hydraulic seal failure and "thief sand?? as the probable contributing factors in the unsuccessful cases. Extremely high aquifer pressure combined with the hydrocarbon buoyancy effects thought to have breached the cap seal mechanical strength which caused capillary hydrocarbon leakages. The presence of post carbonate permeable sandy formation down lapping onto the pinnacle is the other identified geologic risk element. Inter-fingering of the sand and carbonate introduced leak point which provided drainage conduit diverting the hydrocarbon away. The incriminating "blown trap?? theory was thence adopted loosely as an explanation to the situation. On the other hand apparent deeply buried pinnacles are intuitively associated with high formation pressure, temperature and non-hydrocarbon gas contaminants further added up the situation complexity. The anticipated drilling operation complications from such conditions are henceforth associated with potential high costs. These conditions summed up have led to premature condemnation of the remaining carbonate pinnacle play type potential in the region. There was absolutely no interest to further realize the hydrocarbon potential of the pinnacles since then.
Recent works within the region re-evaluating the similar pinnacles have proved the contrary. The pre-conceived misconceptions of the play types were rectified and adoption of the findings proved very rewarding conclusions.