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Faiz, M. Faridyl (Petronas) | Mandal, Dipak (Petronas) | Masoudi, Rahim (Petronas) | Mustapha, Syarizan (Petronas) | Wahab, M. Afiq ab (Petronas) | Nasron, Budi Mawardi (Petronas) | Hadi, Sriyanta (Petronas)
Water injection (WI) to improve oil production and increase reserves had been practiced in Malaysia since 1990s. Currently, around 27 fields are producing with water injection. To better manage these WI fields and gauge the relative performance of these fields, certain Key Performance Area (KPA) and Key Performance Indicators (KPI) were identified. Measurement of these KPA and KPIs serves as a yardstick to compare performance of WI fields and thus provide measures to improve collective performance by promoting replication of best practices and sharing lessons learnt.
In the era of digital technology, the periodic measurement of KPA and KPI has been automated using the existing online platform which can remain accessible to all related parties. It provides a platform for data visualization with simple look forward analysis. The WI data is stored in company databank and the performance dashboard can be viewed from existing software. The team managed to overcome the challenges in completing the historical data gap and data hygiene which previously were managed manually and were not integrated. This resulted in historical evaluation of KPAs and KPIs of certain fields.
This automation initiative will enable practicing engineers to identify the value leakages and proposed mitigation efforts. Some of the best practices identified such as pipeline pigging optimization, correct biocide dosage, periodic calibration of flow meter and chemical optimization already helped to reduce operating cost in certain WI fields.
With these efforts, the company could reduce the operating cost significantly in year 2018. Other than data visualization, the tool provides diagnostic plots such as Hall Plot, Chan's Plot etc. for quick analysis of signs of well/ reservoir health deviations and thus solutions could be provided proactively. On seeing the initial positive results, this tool is being tried for the rest of the WI fields.
This paper details how this tool tries to diagnose all sub-optimal areas within various WI project simultaneously, which leads to operational excellence and improvement in oil recovery, by identifying value leakages, providing proactive solutions with replication of thus identified best practices. Additionally, usage of this tool to rank WI performance of different projects can potentially help to initiate competition between different operators for improvement.
Mandal, Dipak (Oil & Natural Gas Corporation Ltd) | Baruah, Nabajit (Oil & Natural Gas Corporation Ltd) | Jena, Smita Swarup (Oil & Natural Gas Corporation Ltd) | Nayak, Bichitra (Oil & Natural Gas Corporation Ltd)
Hydrocarbon gas injection into the reservoir is one of the most effective EOR processes. In case of a dipping and light oil reservoir, immiscible gas injection can give further impetus to the oil recovery. Since, average current gas saturation in the subject reservoir has become high due to depletion rendering water injection at this late stage is found to be ineffective, scope of gravity assisted immiscible gas injection as an alternative has been evaluated to assess its impact on reservoir pressure and ultimate recovery.
The present study pertains to a high permeable clastic light oil reservoir with reasonable dip, belonging to an old field of South Assam Shelf of India under production since 1990 with current recovery of 22% of STOIIP. The reservoir being undersaturated with no aquifer support, shows significant decline in reservoir pressure (260 ksc of initial pressure to current level of 50 ksc). Simulation study has been carried out on a fine scale geo-cellular model. Multiple realizations have been created considering combinations of oil producers and gas injection wells assigning varied rates to study the different development scenarios and impact on recovery improvement. The study indicates an incremental oil recovery of about 14% of STOIIP by immiscible gas injection.
Based on the study, immiscible gas injection has been initiated in the reservoir on pilot scale basis through two gas injectors with continuous monitoring. After gas injection during last one year, reservoir pressure increased about 25 ksc and consequently per well productivity also increased. Non-flowing well starts producing and currently sand is producing nearly 25% higher than earlier production before gas injection. Based on the encouraging result from pilot gas injection, decided to expand the process at field level and subsequently drilling of new oil producers after jacking up of reservoir.
The study has brought out that the gas injection into shallower portion of the reservoir yields better sweep efficiency to displace the oil to the deeper portion of the reservoir due to the gravity effects and hence, appropriate locales of the reservoir are targeted for additional input generation to augment the oil recovery.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
Jamaludin, Izzuddin (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Arsanti, Dian (PETRONAS Carigali Sdn Bhd) | Dzulkifli, Izyan Nadirah (PETRONAS Carigali Sdn Bhd) | Zakaria, Nurul Azami (PETRONAS Carigali Sdn Bhd) | Mohamad Salleh, Salhizan (PETRONAS Carigali Sdn Bhd) | Ahmad Hawari, Saiful Adli (PETRONAS Carigali Sdn Bhd) | Mohd Azkah, Mohd Zubair (PETRONAS Carigali Sdn Bhd)
Data acquisition remains one of the crucial activities to be consistently executed throughout field life for any oilfield development. Significant operating expenditure (OPEX) is allocated each year to understand reservoir performance, thus reduce uncertainties and enable optimizations. This paper aims to highlight the issues faced during simulation model history matching (HM) process of a waterflood reservoir, including understanding of depositional environment and production data integrity. The output is utilized to improve recovery factor (RF) via infill opportunities and water injection optimization.
Field A has run a second shot of 3D seismic in 2006 (first in 1995) and processed into a time lapse, 4D seismic. In 2014, a cased hole logging campaign utilizing the high precision temperature, spectral noise logging (HPT-SNL) tool has been completed to check the integrity and flow contribution of 12 wells in Reservoir-X. Within the same period, a pulse pressure testing (PPT) was carried out to verify the communication between wells, in addition to acquiring regular surveillance data which helped to improve reservoir simulation study.
The 4D seismic helped to understand the areal waterflood front movement and explained the water cut trend anomaly in an updip well which experienced earlier water breakthrough than near downdip producers. Moreover, it helped to identify a bypass oil zone which can potentially be an infill location. As most of the wells are on dual string completion, the HPT-SNL campaign helped to improve production allocation of multi stacked reservoirs as well as identify problematic wells which required rectification jobs. The PPT assisted in identifying a baffle zone to explain the poor pressure support observed in some producers in the south from the nearby water injectors. All data interpretations were incorporated into final HM model which subsequently identified infill locations and the reservoir management plan (RMP) was successfully revised. An infill program was executed in 2015, which successfully secured additional EUR of ~9 MMstb. Based on the studies and outcome of the infill campaign water injection optimization helped to improve production and added ~2 MMstb reserves, through voidage replacement ratio (VRR) optimization and oil producer (OP) to water injector (WI) conversion. With these efforts, team could successfully project RF of >55%.
This case study demonstrates how acquiring focused surveillance data and their effective integration in performance analysis in simulation study helps to reduce uncertainties, unveils infill opportunities, improves production injection optimization and thus helps to improve the recovery factor in brown fields.
In today's fast paced and challenging oil industry, the need of faster evaluation studies for quick generation of field development plan (FDP) is becoming more crucial to remain competitive. Field's geological and structural complexity, uncertainty of production data adds to the challenges. Traditional approach of building dynamic mesh models carrying out numerical simulation to history match, then predict has always remained time consuming in large mature fields.
The ‘B’ field in Peninsular Malaysia is a mature clastic with stacked reservoirs having a huge gas cap with moderate aquifer. Significant production over last 30+ years led to uneven movement of the gas cap and also of the edge aquifer leading to possibility of bypassed oil. The updated dynamic model could not match the preferential gas cap movement, thus failed to match the high GOR of downdip wells and also unable to match high watercut of certain updip wells. To identify the areas of bypassed oil thus is a significant challenge with the current dynamic model. New engineering tools of polygon balancing, material balance, normalized EUR bubbles were used with the 3D static model volume and the facies understanding. The uncertainties and risks were also identified and clear measurable methods were proposed to address the uncertainties and reduce the risks. Very detailed decision tree with clear data gathering plan to drill successive optimum wells have been planned during the campaign.
This paper details the new engineering tools used to delineate and quantify the bypassed oil in these huge clastic reservoir with preferential gas and water movement, unable to be history matched by the dynamic model. It explains the engineering methods applied to identify and quantify the 10 infill wells proposed for the development campaign. To reduce risks, this paper would also explain the blind testing that was carried out on for this new reservoir engineering analysis tool by deriving the infill potentials of the previous campaign (4 years back) by the same method.
The paper details how robust technical development plans were generated having infill well locations and reserve determination. This paper will also demonstrate the classic "Do-Learn-Adapt" strategy through its infill wells prioritization & ranking, subsurface de-risking analysis, data acquisition and mitigations plans.
Sifuentes, Walter (Schlumberger) | Mandal, Dipak (PETRONAS) | Kumaran, Prashanth Nair (PETRONAS) | Ibrahim, Ramli (PETRONAS) | Chabernaud, Thierry (Schlumberger) | Ceccarelli, Tomasso (Schlumberger) | Moreno, Juan Carlos (Schlumberger) | Sepulveda, Willem (Schlumberger)
This paper aims to describe the overall EOR GASWAG concept with some of the key findings after first phase execution and some of the measures taken to maintain the project within the planned OPEX to remain economic. Secondly, to describe a comprehensive reservoir management plan which includes a fit for purpose data acquisition plan and more importantly how the remaining challenges are addressed through the RMP optimization to maximize recovery. Finally, this paper outlines the main key challenges to be faced once the injection phase kicks off, highlighting the surveillance and monitoring strategies to overcome them.
Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Charbernaud, Thierry (Schlumberger) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Yaakob, Mohd Taufiq (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Ataei, Abdolrahim (PETRONAS Carigali Sdn Bhd) | Maldonado, Jorge (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Iskenova, Gulnara (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Djarkasih, Fredy (Schlumberger) | Abdul Rahman, Nor Nabilah (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Moreno, Juan Carlos (Schlumberger) | Cavallini, Alberto (Schlumberger)
A West Baram Delta prolific mature oil field has been developed through 150+ wells since 1975 in Malaysia. In 2015, an exploration well drilled in neighboring block, successfully found ~500ft TVT of gross oil, 50% less than expected due to structural changes. With lower than expected hydrocarbon in place, the project team was forced to re-evaluate the development and identified key strategies to minimize the number of wells to drill while ensuring healthy project economics. Optimizing reserves and ensuring future accessibility while minimizing number of wells and cost, were the key challenges. Rather than developing all sands with highly deviated well, the team designed an extended reach horizontal well targeting a single key reservoir containing 60% of block STOIIP. Team decided to drill from an existing platform with no pilot hole but opted for real time reservoir mapping technology for well placement. The well was designed with no smart completion due to surface power limitation. First time in the region a dual defensive sand control mechanism was selected, Gravel Pack & Sand Screens. The 1st ever horizontal well was drilled S field meeting its objective at Q4-2017 and exceeding forecasted initial rates. With a long horizontal open hole section and being the only well in the block, a major challenge was to delay water coning and to control water cut once water breaks through. This was achieved with the installation of 8 Inflow Control Devices (ICDs). Real-time reservoir mapping while drilling was used successfully to land the well and then optimize the production section in good quality sands despite structural uncertainty. The well, designed with 60° maximum inclinations, ensures routine well intervention to be done using slickline (i.e. gas lift valve change). Any major intervention would still require coil tubing with usage of barge. The horizontal profile overcomes the limitation of power supply for automation that would be faced with high angle deviated well hence saved significant surface modification cost. The out of box solution of optimized field development plan for complex offshore Brownfield with limited facilities modification, while being cost conscious but technically sound concept proven to provide the answer for sustainable production growth in S Field at low oil price environment. The success of this well has changed the team mindset to relook and propose similar design wells in previously deemed uneconomical FDPs within the S Field.
Waterflooding through water Injection is one of the most effective secondary method to improve oil recovery. Integrated water injection management comprises managing the performance at the reservoir, the wells and the surface and their interdependencies. Lack of effective management of any of these would pose serious concern on incremental recovery due to water injection. Although, water injection (WI) has been in place for many decades, a comprehensive technique to measure the integrated performance of the water injection due to better subsurface management, and/or well management, and/or surface WIM management is not well-established in the industry. Thus it is very difficult to evaluate and compare overall performance of a WI project with the efficiency of other WI projects. In the current times of limited CAPEX spending, thus a technique is required to evaluate various WI projects under the same yardstick, so as to decide on which project more money need to be spent for better returns. Such yardstick which evaluates each of the WI modules (WIM) of subsurface, wells, facilities WIM helps thus then to consider optimal remedial measures to attain excellence. This paper explains how an easy, doable and effective method to evaluate WI performance was generated with help of Key Performance Indicators of the subsurface, wells and surface facilities for a WI project.
This paper reviews the processes which affects the WI performance and identifies Key performance areas (KPA) of influence during Water injection stage. On the basis of merit and impact of each KPA on the overall effectiveness of WI, performance Indexing has been attempted to generate Key Performance Indicators (KPI) in an innovative manner. All KPIs are integrated together with respective weightage factor derived from their individual influence on WI performance into an overall performance indicator. An integrated surface-to-wells-to-subsurface system optimization has been the key consideration during the development of this technique. A worksheet with inbuilt formulae leading to the estimation of all Key Performance Indicators and Overall indicator has been constructed to be used for any WI projects with option of related data inputs. It has been tested on real data of few offshore fields of PETRONAS as sample test and proved to be a valid indicator of WI performance. To test the robustness of the tool it was blind tested by taking out the data of some key injectors in one of the better water flooded reservoirs.
This tool has thus proved effective to gauge the performance of a WI project, remains a measure to compare and rank performance with respect to other WI projects. A continuous plot of the KPIs helps to identify the concerned areas for possible improvement. This technique is thus capable of diagnosing all sub-optimal areas within a WI project simultaneously, which when addressed leads to operational excellence and improvement in oil recovery. Recent usage of this tool to rank WI performance of different projects helped to initiate competition between different operators for improvement.
Kumaran, Prashanth (PETRONAS) | Mandal, Dipak (PETRONAS) | Kadir, Zairi (PETRONAS) | Kamat, Dahlila (PETRONAS) | Ibrahim, Ramli (PETRONAS) | Maldonado, Jorge (Schlumberger) | Iskenova, Gulnara (Schlumberger) | Sharma, Sachin K. (Schlumberger) | Rahman, Mohd Ramziemran Abdul (Schlumberger) | Chabernaud, Thierry (Schlumberger) | Ceccarelli, Tomaso (Schlumberger) | Syahir, Ahmad (Schlumberger) | Djarkasih, Fredy (Schlumberger) | Rahman, Nor Nabilah Abdul (Schlumberger) | Moreno, Juan Carlos (Schlumberger)
In the current period of industry downturn, creating and executing opportunities to develop an offshore brownfield has become more economically challenging. This paper describes the technical, commercial, and operational aspects that helped in achieving an established economical cut-off for project sanction. The project will enable sustaining field average oil production above operational economic limits thereby maximizing field life. With the prevalent low oil price conditions, the economic threshold for projects sanction and execution has reduced. The asset team faced a challenge to achieve a UDC threshold of USD16/bbl. Multi-disciplinary team was tasked to look at key aspects to improve project commerciality. Subsurface recovery potential was assessed thoroughly to evaluate the impact of subsurface uncertainty, and evaluate the impact on well designs on the project cash flow. Wells were designed to tap multiple reservoir targets to minimize subsurface risk through existing facilities to maximize ullage. The wells were drilled from new slots via small deck extension instead of the high-risk slot recovery option, which helped to reduce the Capital Expenditure (CAPEX). Fit-for-purpose and cost optimized wells were designed by minimizing automation (i.e.: ICVs, PDGs, etc.) which also reduced operating risk and cost. Multiple sands were targeted in different compartments with different pressure system, hence planned not to commingle production. Hence, only one primary reservoir was completed, with other zones kept behind casing for future intervention with bottom-up production strategy. This helped deferring the project investment as this was in the intervention cost in Operating Expenditure (OPEX) which helped to improve the project economics. Further cost savings were achieved by accelerating the project in order to achieve synergy with an upcoming drilling campaign. The reduction of the overall project CAPEX, thus allowed the project to be commercially feasible and technically sound for execution. In addition, the team has also established a reservoir management plan with mitigation plan to deal with the main subsurface and surface risks. The out of box solution of optimized field development plan for complex offshore brownfield with limited facilities modification, while being cost conscious but still ensuring technically sound concept proved to provide the answer for sustainable production growth in S Field at low oil price environment. This paper will also highlight the key lessons learnt and obstacles which were observed during the execution of the project are expected to become guidelines for future low cost projects in this region.
Chuen, C. Mabel Pei (Petronas Carigali Sdn. Bhd.) | Nukman, M. Agus (Petronas Carigali Sdn. Bhd.) | Mandal, Dipak (Petronas Carigali Sdn. Bhd.) | Salim, A. S. H. Ahmad (Schlumberger WTA Malaysia Sdn. Bhd.) | Sepulveda, W. (Schlumberger WTA Malaysia Sdn. Bhd.) | Vaca, J. C. (Schlumberger WTA Malaysia Sdn. Bhd.) | Goh, K. (Schlumberger WTA Malaysia Sdn. Bhd.)
Overproduction of water is an inevitable risk in most mature oil fields. Operators have a high expenditure in both OPEX and CAPEX to delay the influx of water production, which is reducing both field life and economic value. With the advent of reservoir control technologies, oil production wells are now fitted with downhole pressure and temperature gauges and downhole flow control valves (FCV). These ‘intelligent’ wells provide valuable data for reservoir surveillance, and operators can control drawdown pressure to reduce water influx from high water production reservoirs. However, further analysis is required to identify zonal productivity index (PI) and water cut (WC) of each reservoir layer, before engineers can decide and manipulate the FCV flow area configuration of each reservoir flowing in a commingled setting. The current process of allocation using production logging is less efficient while layer-by- layer testing will cause deferments to a well's production. In offshore fields, the delay to production in order to make way for data acquisition is undesirable due to logistical difficulties. This project aims to build an optimizer to allocate reservoir parameters; PI and WC in commingled intelligent wells; and determine the most optimal setting for the FCV flow areas which will maximize oil production. This is built using data from downhole gauges, well modelling software and a multi software platform simulator (MSPS). The inbuilt algorithm in MSPS will allocate PI and WC to match simulated data calculated by a well model, to actual data from the field instruments with the lowest error possible. Once the PI and WC of each layer are known, FCV flow area settings can be configured to yield the optimal oil production. From the pilot on one well, the optimizer successfully helped engineers to increase oil production from 300 to 430 bopd in two months, while mantaining a steady yet maintainable WC increase of 11%, without any intervention costs or deferment. The allocated reservoir PI and WC allow engineers to strategize reservoir management plans specific to each producing reservoir layers, thus, improving the mechanism for reservoir surveillance.