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Abstract The nanoparticles are considered as an attractive emerging improved oil recovery technique in last decade due to its ability to propagate deeper into pore throat and displace unswept oil in the reservoir. Current understanding of its mechanisms in conventional oil has been observed so called disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper presents recent investigation of new potential mechanism during development of nanofluids to improve oil recovery in Malaysian oilfield. The new inhouse nanofluids was developed using acrylamide monomers that were grafted on the surface of silica-based nanoparticles. A minor concentration of surfactant was introduced into the formulation to observe synergistic effect. The nanoparticles were characterized under electron microscope. Compatibility and thermal stability tests were conducted using reservoir fluids at reservoir temperature. The rheology of fluids was measured during monitoring of stability. In term of wettability alteration, sequence fluid-fluid and rock-fluid tests were conducted includes dynamic interfacial tension (IFT) and optical contact angle (OCA) measurement. The particle size was measured with size around 20 nm. Adding small concentration of additive showed good performance in term of compatibility, thermal stability, and wettability alteration through IFT reduction and OCA measurement. Nanofluids with additive provided excellent compatibility with reservoir fluids and stable at reservoir temperature over 60 days. Its viscosity was also more stable during observation period without creating micro-emulsion. The IFT reduced insignificantly from 2.6 to 1 mN/m and when introduced additive, the IFT reduction achieved 0.01 mN/m. This synergistic effect was observed during IFT measurement and called as fragmentation. Our recent finding leads to provide new reference for displacement mechanism using next generation of nanofluids and offers further potential of nanoparticles with multiple mechanisms and rapid synergistic effects prior its application in in Malaysian oilfield.
- North America > United States (1.00)
- Asia (1.00)
A Toolkit for Offshore Carbon Capture and Storage CCS
Tewari, Raj Deo (PETRONAS) | Tan, Chee Phuat (PETRONAS) | Sedaralit, M. Faizal (PETRONAS)
Abstract Carbon dioxide (CO2) capture, utilization, and storage is the best option for mitigating atmospheric emissions of CO2 and thereby controlling the greenhouse gas concentrations in the atmosphere. Despite the benefits, there have been a limited number of projects solely for CO2 sequestration being implemented. The industry is well-versed in gas injection in reservoir formation for pressure maintenance and improving oil recovery. However, there are striking differences between the injection of CO2 into depleted hydrocarbon reservoirs and the engineered storage of CO2. The differences and challenges are compounded when the storage site is karstified carbonate in offshore and bulk storage volume. It is paramount to know upfront that CO2 can be stored at a potential storage site and demonstrate that the site can meet required storage performance safety criteria. Comprehensive screening for site selection has been carried out for suitable CO2 storage sites in offshore Sarawak, Malaysia using geographical, geological, geophysical, geomechanical and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generating performance scenarios of the site. In addition, the geochemical interaction of CO2 with reservoir rock has been studied to understand possible changes that may occur during/after injection and their impact on injection processes/mechanisms. Novel 3-way coupled modelling of dynamic-geochemistry-geomechanics processes were carried out to study long-term dynamic behaviour and fate of CO2 in the formation. The 3-way coupled modelling helped to understand the likely state of injectant in future and the storage mechanism, i.e., structural, solubility, residual, and mineralized trapping. It also provided realistic storage capacity estimation, incorporating reservoir compaction and porosity/permeability changes. The study indicates deficient localized plastic shear strain in overburden flank fault whilst all the other flaws remained stable. The potential threat of leakage is minimal as target injection pressure is set at initial reservoir pressure, which is much lower than caprock breaching pressure during injection. Furthermore, it was found that the geochemical reaction impact is shallow and localized at the top of the reservoir, making the storage safe in the long term. The integrity of existing wells was evaluated for potential leakage and planned for a proper mitigation plan. Comprehensive measurement, monitoring, and verification (MMV) were also designed using state-of-art tools and dynamic simulation results. The understanding gaps are closed with additional technical work to improve technologies application and decrease the uncertainties. A comprehensive study for offshore CO2 storage projects identifying critical impacting elements is crucial for estimation, injection, containment, and monitoring CO2 plume. The information and workflow may be adopted to evaluate other CO2 projects in both carbonate and clastic reservoirs for long-term problem-free storage of greenhouse gas worldwide.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
Monitoring, Measurement and Verification MMV: A Critical Component in Making the CO2 Sequestration Success
Tiwari, Pankaj Kumar (PETRONAS) | Das, Debasis Priyadarshan (PETRONAS) | Patil, Parimal Arjun (PETRONAS) | Chidambaram, Prasanna (PETRONAS) | Low, Zoann (PETRONAS) | Azahree, Ahmad Ismail (PETRONAS) | Amir Rashidi, M. Rashad (PETRONAS) | Mohd Ali, Syareena (PETRONAS) | Jaafar Azuddin, Farhana (PETRONAS) | Mhd Shah, Sahriza Salwani (PETRONAS) | Widyanita, Ana (PETRONAS) | Abdul Jalil, M. Azran (PETRONAS) | Abu Bakar, Zainol Affendi (PETRONAS) | Abdul Hamid, M. Khaidhir (PETRONAS) | Tewari, Raj Deo (PETRONAS) | Yaakub, M. Azriyuddin (PETRONAS)
Abstract The increasing atmospheric concentration of carbon dioxide (CO2), a greenhouse gas (GHG) is creating environmental imbalance and affecting the climate adversely due to growing industrialization. Global leaders are emphasizing on controlling the production of GHG. However, growing demands of natural gas, industry is embarking on the development of high CO2 contaminant gas fields to meet supply gap. Development and management of contaminated hydrocarbon gas fields add additional dimension of sequestration of CO2 after production and separation in project management. CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, measuring and verification (MMV) of injected CO2 volume in sequestration is critical component along with geological site selection, transportation, storage process. The present study discusses all the impacting parameters which makes whole process environment friendly, economically prudent and adhering to national and international regulations. The migration of injected CO2 plume in the reservoir is uncertain and its monitoring is equally challenging. The role of MMV planning is critical in development of high CO2 contaminant fields of offshore Sarawak. It substantiates that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection and possesses minimum to no risk to HS&E. The deployment of Multi-Fiber Optic Sensor System (M-FOSS) promises a cost-effective solution for monitoring the lateral & vertical migration of CO2 plume by acquiring 4D DAS-VSP (Distributed Acoustic Sensor – Vertical Seismic Profile) survey and for the well integrity by analyzing DAS/DTS (Distributed Temperature Sensor)/DPS (Distributed Pressure Sensor)/DSS (Distributed Strain Sensor) data. Simulation results and injectivity test at laboratory for in-situ CO2 injection has demonstrated the possibility of over 100MMscfd/well injection in aquifer to meet the total CO2 injection of 1.2Bscfd for full field development while maintaining the reservoir integrity. Uncertainty & risk analysis shows possible presence of seismically undistinguished fractures and minor faults, an early breakthrough of injected CO2 cannot be ruled out. The depleted reservoir storage study divulges the containment capacity of identified carbonate reservoirs as well as conformance of potential storage sites. The fault-seal analysis and reservoir integrity studies determine the robustness of the long-term security of the CO2 storage. Injectivity study demonstrates the optimum and maximum possible rates of CO2 injection into these depleted gas reservoirs. VSP simulation results show that a subsurface coverage of 3-4 km per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. The deployment of M-FOSS technology is novel and proactive approach to monitor the CO2 plume migration and well integrity. First ever development of MMV Planning for CO2 Sequestration in offshore Sarawak, Malaysia using novel and cutting-edge M-FOSS technology for proactive monitoring of CO2 plume migration and well integrity.
- North America > United States (1.00)
- Asia > Malaysia > Sarawak > South China Sea (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology (0.94)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Understanding the Effect of Rock Compressibility on CO2 Storage Capacity Estimation in a Depleted Carbonate Gas Reservoir
Chidambaram, Prasanna (PETRONAS Research Sdn Bhd) | Tewari, Raj Deo (PETRONAS Research Sdn Bhd) | Mohd Ali, Siti Syareena (PETRONAS Research Sdn Bhd) | Tan, Chee Phuat (PETRONAS Research Sdn Bhd)
Abstract Avoiding or reducing greenhouse gases emission in the atmosphere requires extensive application of technologies and one of them is underground CO2 sequestration. Capture and storage of CO2 in depleted hydrocarbon reservoirs can reduce greenhouse gases released into the atmosphere effectively. Hydrocarbon reservoirs are considered one of the ideal geologic storage sites as they have held hydrocarbons over millions of years. Their architecture and properties are well understood due to exploration and production activities from these reservoirs. Storage projects require a large depleted hydrocarbon reservoir with good reservoir properties and are affected by several factors including voidage created by hydrocarbon production, pressure, architecture, formation permeability, aquifer influx, subsidence and compaction, and rock compressibility to name a few. Thus, realistic estimation of the storage capacity of the reservoir is a key step in the evaluation of CO2 storage plan. A good history matched simulation model incorporating the geomechanical parameters is essential to estimate storage capacity of the reservoir. Three major depleted gas reservoirs in Central Luconia field, located in offshore Sarawak, are being evaluated for future CO2 storage. Reservoir simulation is used as a tool to estimate future CO2 storage capacity of these reservoirs. Reliability of forecast from a reservoir simulation model is dependent on the quality of history match achieved. Hence it is believed that CO2 storage capacity estimates obtained from a good history matched simulation model must be reliable. However, during history matching exercise in these reservoirs, it was observed that an acceptable history match could be achieved with a range of rock compressibility values and aquifer influxes. Generally, a constant value of rock compressibility is used in conventional simulation. For example, in order to obtain an acceptable history match, with a lower compressibility, a larger aquifer influx is needed and vice versa. Interestingly, a forecast using these history match cases yield different CO2 storage capacities. A closer evaluation shows that aquifer influx has a strong impact on future CO2 storage capacity. An acceptable quality of history match can be obtained for a range of rock compressibility values when aquifer influx is adjusted along with it. Sensitivity analysis shows that future CO2 storage capacity in depleted hydrocarbon reservoir is sensitive to rock compressibility used in the simulation model. A detailed sensitivity analysis along with multiple history match scenarios is necessary to understand the range in future storage capacity when evaluating CO2 storage plan.
- North America > United States (0.94)
- Asia > Malaysia > Sarawak > South China Sea (0.87)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Easy Steps in Probabilistic Dynamic Modelling in FDP
Anupam, Ankesh (Schlumberger) | Tewari, Raj Deo (Petronas)
Abstract Adequate implementation of probabilistic dynamic modelling workflow allows to explore full range of solutions and helps in better decision making. Probabilistic modelling workflows comprise of a series of steps. This paper closely scrutinizes three key steps of a probabilistic workflow – sensitivity analysis, experimental design and model selection for decision making. There are different methods and processes practiced in the industry for these key steps. A comparative study of commonly available and practiced techniques is performed, and their pros and cons are demonstrated using open available Brugge field model. In the first part the commonly used tornado/one variable at a time (OVAT) is compared against other global sensitivity techniques suchas ANOVA (Analysis of Variance) and multi-regression analysis. The difference among the techniques is explained and its application is demonstrated through field example. It is shown that the global sensitivity analysis is more robust and provides better results but at a higher computational cost. Next experimental design techniques are reviewed with focus on the optimum experimental design. Key concepts of experimental design such as aliasing, resolution and confounding pattern are explained. It is shown that an appropriate experimental design can be used to avoid confounding of key parameters. The confounding patterns have been demonstrated for factorial design experiments. The concept is shown with the example of Brugge model. Model selection after history matching process is a challenging task. In the last part of the paper two different multi-dimensional visualization techniques PCA (Principal Component Analysis) and t-SNE (t-Stochastic Neighbour Embedding) are explained and utilized to visualize the ensemble of history matched models. These techniques in combination with k-mean clustering has been used to select representative models for prediction. The overall uncertainty captured by the representative models is compared to the full ensemble of history matched models. It is shown that clustering along with visualization provide a robust framework for model selection. The paper is intended to provide a good understanding of some of the key steps of the probabilistic modelling workflow. The technical concept behind each technique is briefly described but the main focus is on the practical aspects and implemtation of these techniques.
The Concept of Need for a Downhole Scale Inspection Tool: An Appraisal for an Emerging Technology in Scale Management
Zoveidavianpoor, Mansoor (PETRONAS Research) | Rosland, Eadie Azahar (PETRONAS Carigali) | Laakkonen, Pasi (Rocsole) | Aryana, Saman (University of Wyoming) | Jaafar, Mohd Zaidi (Universiti Teknologi Malaysia) | Ibrahim, Jamal Mohamad (PETRONAS Research) | Kolivand, Hoshang (Liverpool John Moores University) | Tewari, Raj Deo (PETRONAS Research) | Johar, Razman Marsoff (PETRONAS Research) | Mohamed, Zaidi Awang (PETRONAS Carigali) | Salleh, Intan Khalida (PETRONAS Research)
Abstract Monitoring techniques in oilfield scale management are expensive, susceptible to error, are not conducted in real-time, and they are non-in situ. Most scale prediction tools (i.e., water analysis and computer-based algorithms) have their deficiency and the need for accurately correlate calculated scaling tendencies with actual field data is evident. Lack of info about type, severity and location of scale deposits can lead to the failure of well intervention jobs. This work aims to serve as an opportunity to provide fertile ground and basis for utilizing new emerging technology for scale management in downhole application. Research into utilizing sensors along with an advanced computerized imaging procedure in the downhole application has not been explored to the same extent as other applications, such as scale monitoring in pipelines and surface facilities. Downhole Scale Inspection Tool (DSIT) is a new emerging technology which promises to enhance considerably our ability to detect deposits and scale with the aim of sensors and tomography technology. DSIT has enormous potential for application in downhole condition as it uses slickline unit alongside with routine well intervention jobs. The acquired data by DSIT such as temperature, pressure, depth, deposition thickness and permittivity are utilized for downhole scale analysis, monitoring and detection. When the type of scale is known, it is easier to take the correct steps in preventive maintenance or a cleaning process. Using DSIT, the trend of deposition thickness can be detected and immediately known if it is growing or shrinking. This will help to optimize any chemical feed and also generate substantial savings over time. This paper gives an overview of developing cutting-edge technology in downhole applications for scale management and possible barriers to new technology implementation. Using DSIT can lead to better data acquisition from downhole and contribute to a higher success rate of scale removal in downhole. This technique offers many benefits for scale treatment, monitoring and prediction when filed data is necessary for validation of scaling tendencies.
Abstract Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO2, H2S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO2-brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO2 like membrane and cryogenics for bulk separation of CO2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO2 for industrial use is highlighted.
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
FEP Based Model Development for Assessing Well Integrity Risk Related to CO2 Storage in Central Luconia Gas Fields in Sarawak
Patil, Parimal A. (PETRONAS) | Chidambaram, Prasanna (PETRONAS) | Bin Ebining Amir, M Syafeeq (PETRONAS) | Tiwari, Pankaj K. (PETRONAS) | Das, Debasis P. (PETRONAS) | Picha, Mahesh S. (PETRONAS) | B A Hamid, M Khaidhir (PETRONAS) | Tewari, Raj Deo (PETRONAS)
Abstract Underground storage of CO2 in depleted gas reservoirs is a greenhouse gas reduction technique that significantly reduces CO2 released into the atmosphere. Three major depleted gas reservoirs in Central Luconia gas field, located offshore Sarawak, possess good geological characteristics needed to ensure long-term security for CO2 stored deep underground. Long-term integrity of all the wells drilled in these gas fields must be ensured in order to successfully keep the CO2 stored for decades/centuries into the future. Well integrity is often defined as the ability to contain fluids without significant leakage through the project lifecycle. In order to analyze the risk associated with all 38 drilled wells, that includes 11 plugged and abandoned (P&A) wells and 27 active wells, probabilistic risk assessment approach has been developed. This approach uses various leakage scenarios, that includes features, events, and processes (FEP). A P&A well in a depleted reservoir is a very complex system in order to assess the loss of containment as several scenarios and parameters associated to those scenarios are difficult to estimate. Based on the available data of P&A wells, a well has been selected for this study. All the barriers in the example well have been identified and properties associated with those barriers are defined in order to estimate the possible leakage pathways through the identified barriers within that well. Detailed mathematical models are provided for estimating CO2 leakage from reservoir to the surface through all possible leakage pathways. Sensitivity analysis has been carried out for critical parameters such as cement permeability, and length of cement plug, in order to assess the containment ability of that well and understand its impact on overall well integrity. Sensitivity analysis shows that permeability of the cement in the annulus, and length of cement plug in the wellbore along with pressure differential can be used as critical set of parameters to assess the risk associated with all wells in these three fields. Well integrity is defined as the ability of the composite system (cemented casings string) in the well to contain fluids without significant leakage from underground reservoir up to surface. It has been recognized as a key performance factor determining the viability of any CCS project. This is the first attempt in assessing Well Integrity risk related to CO2 storage in Central Luconia Gas Fields in Sarawak. The wells have been looked individually in order to make sure that integrity is maintained, and CO2 is contained underground for years to come.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Petroleum Play Type (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- (5 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Well Integrity (1.00)
- (4 more...)
Designing of Successful Immiscible Water Alternating Gas (IWAG) Coreflood Experiment
Khanifar, Ahmad (EOR Program, Technical Global, PETRONAS) | Raub, Mohd Razib Abd (EOR Program, Technical Global, PETRONAS) | Tewari, Raj Deo (EOR Program, Technical Global, PETRONAS) | Zain, Zahidah M (EOR Program, Technical Global, PETRONAS) | Sedaralit, M Faizal (EOR Program, Technical Global, PETRONAS)
Abstract Average recovery factor in offshore field under discussion is relatively moderate due to wider well spacing and poor sweeping efficiency thus leaving significant volume of oil behind in the reservoir. Timely application of EOR is therefore necessary to enhance the recovery factor to a reasonable level. Among the various EOR processes and techniques of EOR screened, studies found immiscible water-alternating gas (IWAG) injection as the most suitable and viable option for this Malaysian mature offshore oilfield. Realistic estimate of incremental oil by EOR is paramount as IWAG application involves high CAPEX and OPEX project. Therefore, representative is required to be generated in the laboratory for constructing a realistic reservoir simulation model to understand the three phase flow in porous media and support the IWAG process for full field implementation. Important parameters in this case are residual oil saturations in sequential injection of displacing fluids water and gas and trapping of gas, injection volumes and frequency of alteration. Therefore, IWAG core flooding experiments under reservoir conditions need to be performed, results quantified and parameters for hysteresis modeling established. This paper addresses the challenges and strategies of IWAG core flooding experiment performed under reservoir conditions using representative composite native cores, live reservoir oil sample, field produced gas sample and synthetic formation brine water. The laboratory injection rates are considered equivalent to the field fluid advance velocity like in any standard displacement steps. Also, gravity stable injection mode is considered to achieve the best IWAG displacement performance. These challenges and strategies are drawn from lessons learned during accomplishment from earlier IWAG core flooding experiments. The IWAG core flooding experiments were performed on composite field core samples, arranged according to Langaas method, using current field production gas with 60 mole % CO2. The composite reservoir core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water and seawater to residual oil saturation at reservoir conditions. Following, waterflooding, a number of water and gas cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO2 content produced gas indicated that 7.0 % additional oil recovery over waterflooding period can be recovered.
- North America > United States > Texas (0.46)
- Asia > Malaysia > Terengganu > South China Sea (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 6 > Dulang Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Betty Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Pubei Field (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Guntong Field (0.98)
An Integrated Methodology to Locate the Remaining Oil Opportunities in Mature Reservoirs in offshore Sarawak, Malaysia
Zulhaimi, Muhammad Jazlan (EORC) | S. Wan Ibrahim, Wan Mohd (EORC) | Sanyal, Satyashis (EORC) | Zamri, Khairul Azhar (EORC) | Mohamad, Muhammad Naim (EORC) | M Zaini, Khairul Nizam (EORC) | Tewari, Raj Deo (PETRONAS Carigali Sdn. Bhd.) | Pradhan, Akshaya Kumar (PETRONAS Carigali Sdn. Bhd.)
Abstract The matured field is located in the Sarawak offshore, Malaysia. Discovered in 1968, the field is an anticlinal structure with vertically stacked reservoirs deposited in a shoreface environment. The brown field has been producing under active aquifer drive with a very high recovery factor. The field is currently producing with more than 85% WC and has significant levels of uncertainties with respect to oil-water contacts, flank structure, depth of spill points, production allocation, SCAL and residual oil saturation. Major challenges were observed in building fine static models for further dynamic simulation work. A coarse mega model were built covering all reservoirs to capture the STOIIP uncertainties in the field as well as to support an integrated conventional approach to locate the remaining oil and estimating the potential infill reserves. A robust workflow were developed to identify the infill opportunities by integrating material balance study, case hole logs information, water diagnostic plots, decline curve analysis and many more. The comprehensive LTRO methodologies applied has been successful in identifying the location of the remaining oil as well as estimating the potential reserve. This approach has also managed to accelerate field development plan and afforded the team efficient resource optimization by avoiding the more time consuming re-cycling the conventional static-dynamic modeling approach. Introduction The field is located 20 km offshore Sarawak in water depths of 100 ft. The field, which was discovered in May 1968, fell under the BDO PSC, which was to expire on 31stMarch 2018. A new EOR PSC was signed on 16thJanuary 2012, which extends the expiry date to 2040. The field structure consists of a 30,000 by 9,000 ft elongated anticline running NE-SW and comprises a series of stacked reservoirs at a depth of 4000 to 9500 ft. The field is considered structurally simple, with a normal growth fault affecting only the deep reservoirs and no other faults visible on 2D seismic or in the wells. The field reservoirs were deposited some 20–23 million years ago during Cycle V of the late Miocene in a lower coastal plain to coastal environment. The depositional environment of this field is dominated by a sequence of shore-face deposits, which formed 6–11 million years ago during Cycle V of the late Miocene. Sands are loosely consolidated, fine to very fine grained and interbedded with layers of silts and clays. Porosity ranges from 14 to 26 % with a field-wide mean of 20%. The permeabilities are in the order of 50 to 3000mD. Net sand thicknesses are less than 30 ft, with most individual sands around 10 ft. The reservoirs are subdivided into three categories (Figure 1): Shallow Reservoirs at depths of 4000 to 5300 ft, which are characterized by large gas caps and mostly thin oil rims, and are currently considered unfaulted.
- Asia > Malaysia (0.86)
- North America > United States > Texas (0.55)
- Europe > United Kingdom > North Sea (0.34)