Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope.
An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as: To establish reservoir properties & characterization To measure formation pressure and acquire fluid sample To establish reservoir injectivity and productivity at the prospective intervals To acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.
To establish reservoir properties & characterization
To measure formation pressure and acquire fluid sample
To establish reservoir injectivity and productivity at the prospective intervals
To acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.
The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1.
Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.
Chia, Mabel Pei Chuen (PETRONAS) | Yakup, M Hamzi B (PETRONAS) | Tamin, Muhammad (PETRONAS) | Surin, Nicholas Aloysius (PETRONAS) | Mazzlan, Khairul Akmal B (PETRONAS) | Rinadi, M (PETRONAS) | Hassan, A Azim B (PETRONAS)
This paper details out the application of a predictive analysis tool to'S' Field's commingled production, aiming to enhance production allocation and reservoir understanding without the need of well intervention and a reduced frequency of zonal rate tests and data acquisition. Allocation of the production data to its respective reservoirs is performed via a novel Multi-Phase Allocation method (MPA), taking into account the water production trending evolution derived from relative permeability behavior of oil-water in each reservoir to compute flow rates for liquid phases over time. The precision of the derived rates is constrained by actual zonal rates tests through Inflow Control Valves (ICVs). This method will be cross referenced against'S' Field's existing zonal rate calculation algorithm, utilizing input data from well tests results and real time pressure and temperature data. The MPA method demonstrates improvement in the allocation of production data as compared to the conventional KH-methodology as MPA takes into account the water cut trending between reservoirs. Leveraging on ICVs to obtain actual zonal rate measurements, this greatly reduces the range of uncertainty in the allocation process. MPA derived production split ratios closely match the split ratios derived from the'S' Field's existing zonal rate calculation algorithm, which utilizes input data from well tests results and real time pressure and temperature data from down hole gauges. It is observed that the usage of actual measured zonal rate tests reduces the range of uncertainty of the MPA data. A combination of novel multiphase deliverability models coupled with smart field technologies such as intelligent completions and real-time surveillance and analysis tools will increase the accuracy of the back allocation of multiphase production data in commingled reservoirs.
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.
Amsidom, Amirul Adha (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Alexander, Euan (PETRONAS) | Kuswanto, Kuswanto (PETRONAS) | Abdullaev, Bakhtiyor (PETRONAS) | Hassan, Hani Sufia (PETRONAS) | Ishak, M Faizatulizudin (PETRONAS) | Rajah, Benny (PETRONAS) | Gunasegaran, Puvethra Nair (PETRONAS) | Ayad, Kamal (Cornerstone for Business Development) | Madon, Bahrom (PETRONAS) | Hamzah, M Amir Shah (PETRONAS) | Zamanuri, Kautsar (PETRONAS)
About 80% of brownfields in Malaysia use Gas Lift as the artificial lift method. Though it is widely used, the operators are facing numerous challenges which include shortages in gas lift source and compressor reliability issues. Consequently fields’ productivity is impacted and results in higher operating expenditure. A case of change from Gas Lift to ESP was studied however due to high rig costs many of these the projects are uneconomic. Given this is the case PETRONAS had been researching the use of high speed slim, power- cable deployed ESPs for installation inside 2- 7/8" and 3-1/2" tubing (TTESP-CD). The challenge was to develop a deployment method using intervention techniques to comply with process safety requirements and installation over a live well without any workover rig. The associated technologies to enable deployment and operation of the ESP were identified, modified, developed and qualified as required in order to meet API 6A, API 14A and ISO 14310.
In order to meet the project objectives and derisk technical uncertainties, an onshore test run and offshore pilot were planned. These ensured the design requirements of the key deployment technologies met relevant API and ISO standards; 1) wellhead adapter for cable exit and load handling 2) the anti-rotation anchor packer and 3) the insert safety valve, 4) wireline unit, 5) pressure control equipment. Each of the technologies developed or modified are key components of the deployment technique. Through the onshore testing, the deployment procedure and running equipment were improvised to fit the offshore pilot installation.
The deployment of the TTESP-CD system offshore was a success; the ESP was installed within 3-1/2" 9.2ppf tubing to a depth of 1752ft over a live well using the modified deployment package. The actual ESP deployment took around 5days including rig up/down of the deployment package. Running the ESP to depth only took around 8hrs including setting the insert safety valve. Major time consuming events were assembling the ESP, cable space- out, cable termination/splice, landing hanger and cleaning out the electrical connections. Looking forward; this is a technology PETRONAS see great value in for Malaysian and international assets. Currently there are plans for four more installations in 2018 and a minimum of five installations in 2019.
The PETRONAS led team have overcome challenges the industry has faced for many years with regards to this type of ESP deployment by investing in R&D and committing resources. By developing this technology PETRONAS and its technology providers have officially opened up market for low cost ESP deployment which is a significant step change to conventional practice. This will be of great benefit to the upstream oil and gas industry, particularly for offshore assets with little infrastructure.
Sazali, Wan Muhammad Luqman (PETRONAS) | Md Shah, Sahriza Salwani (PETRONAS) | Kashim, M Zuhaili (PETRONAS) | Kantaatmadja, Budi Priyatna (PETRONAS) | Knuefing, Lydia (Australian National University) | Young, Benjamin (Thermo Fisher Scientific) | Goodwin, Carley (Ohio State University)
There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.
Uncertainty and risk analysis is an inseparable part of any decision making process in the field development planning. This study sheds light on the available approaches to capture the range of uncertainties but digs deep into the misuses of the probabilistic approach that renders the method difficult and time consuming to implement with little added value for risk mitigation and proper decision making.
Probabilistic modeling using dynamic simulation models has been adopted in recent decades to address the variations in forecasted production profiles and to capture the uncertainties. However, there are misuses in the approach that pose questions on the outcome and its meaningfulness. Lack of enough spread in the forecast, history-matched models with physically incorrect parameter ranges/ combinations and models suggesting contradicting development scenarios are among examples. These in turn make the probabilistic forecasting output inconclusive and considering the high computational cost and time required to perform the exercise makes it unattractive to management. In this paper four case studies including mature and green fields have been described and a number of main issues and pitfalls of using probabilistic dynamic modeling in those cases are analyzed. General workflows are then presented for green and brown fields based on experimental design, proxy modeling, optimization and prediction candidates selection that provides solution for proper selection and implementation of the probabilistic dynamic modeling.
It is argued that probabilistic modeling can help better capture the uncertainties and reduce the risk in field development planning provided that a fit-for-purpose approach is taken with correct understanding of the data requirement according to the reservoir complexity, the physical processes being modeled and assumptions used in the methodologies and simulation engines. This is in contrast to the attempts to capture the ranges of recoverables based on deterministic high and low cases that is often inefficient as the optimistic high-case of ‘hole-in-one’, may suggest an ideal but not plausible scenario whereas the pessimistic low-case of ‘train-wreck’ may be economically unattractive. The exercise then leaves the companies with the best technical estimate model to make the final call and the numbers from other models are only used for reserve booking purposes.
The published papers in the literature include discussions on deterministic vs. probabilistic approaches and selection of base case models, the detailed algorithms and also case studies done using the published methods available in the commercial softwares. This paper however discusses the misuses of the probabilistic dynamic modelling approach and tries to inform the audience of the pitfalls of not understanding the reservoir and/or the tools used in implementing the methods and in this sense it is novel.
Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (
These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG).
In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP).
The previously published workflow by the authors (
M. Johan, M. Alham (EnQuest Malaysia) | Al Zayani, Sirag (EnQuest Malaysia) | Moritz, Arthur Lee (EnQuest Malaysia) | Taylor, Charles (EnQuest Malaysia) | Wibisono, Rahmat (PETRONAS) | M. Mokhtar, Shahril R. (PETRONAS) | Thian, Kelvin (Halliburton) | Samvelova, Marina (Halliburton)
As a low-cost alternative to expensive rig workovers, placement of a cement packer between tubing and casing has been previously applied in Malaysia. The purpose is to create a new annular barrier above the existing production packer to gain access to behind-casing opportunities (BCOs) or pay zones, removing the need for a workover. These pay zones, usually with minor or unknown production potential, have been left by the operator during initial completion because there were larger pay zones in deeper reservoirs. Cement packer placement can be achieved using basic intervention equipment as opposed to more expensive workover units.
The cement packer technique eliminates the need of recompleting the well with a conventional workover rig and reduces operational complications together with cost. There are different methods to deploy a cement packer. The highest chance of success, particularly when larger volumes of cement are needed, is using coiled tubing (CT) as the primary method to place the cement slurry in the tubing/casing annulus. In this method, a cement retainer was used and conveyed with CT. CT provides the ability to sting into the retainer and cement being displaced through the coil, ensuring all completion accessories have no contact with cement slurry which can impair their functionality, and also prevents U-tube effect of the slurry once cement is placed behind the tubing. After the cement is set, a cement bond log (CBL) is run to confirm cement integrity behind the completion tubing before adding new perforations.
This paper presents the successful cement packer placement operation with the help of the CT executed on an offshore platform in Peninsular Malaysia. A potential pay zone of the I-Group reservoir was discovered in the field after running pulsed-neutron cased-hole saturation logging tools, which are situated above the production packer; appraisal was required because of the unknown fluid type. Close collaboration among various parties in candidate selection, job preparation and design, cement laboratory testing, and operational planning and execution, were keys to the success of this pilot operation. By proving operational feasibility and economics, the technique opened up additional opportunities in restoring idle wells with bypassed reserves within the same field.
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.
Razak, M. Firdaus B. (PETRONAS) | Khalid, Aizuddin (PETRONAS) | Sapian, Nik Fazril Ain (PETRONAS) | Madzidah, Asba (PETRONAS) | Samuel, Orient Balbir (PETRONAS) | Khalid, M. Zaidan B. (PETRONAS) | Mohd, Shamsulbahri B. (PETRONAS) | Bakar, M. Farris (PETRONAS) | Salih, Mohamed Sharief Saeed (PETRONAS) | Ruvalcaba, Jazael Ballina (PETRONAS) | Sadan, Nur Syazana (PETRONAS) | Misron, M. Al-Perdaus B. (PETRONAS) | Afzan, A. Satar (PETRONAS) | Jamal, Ajmal Faliq B. (PETRONAS) | A'akif, Nurul Aula bt (PETRONAS) | Mohr, Ludovic (PETRONAS) | Tajuddin, Nor Baizurah bt Ahmad (PETRONAS) | Kalidas, Sanggeetha (SCHLUMBERGER) | Faizah, P. Mosar Nur (SCHLUMBERGER) | Goh, Gordon (SCHLUMBERGER) | Tan, Tina (SCHLUMBERGER) | Palanisamy, Ravishankar (SCHLUMBERGER) | Luke, Darren (SCHLUMBERGER)
The ‘B’ Field is located about 40 KM, offshore Sarawak and was discovered in 1967 with 70-80 m water depth. Structurally, ‘B’ field is charaterised by a simple relatively flat, low-relief domal anticline which is bounded to the north and south by the north-hading growth faults. The major faults are acted as effective lateral seal, which is indicated by the difference in the fluid type and fluid contacts across those faults. ‘B’ field consist of multiple hetereogenous sandstone reservoirs with permeability and porosity ranging from 25 −1700 mD and 16 −29% respectively.
‘B’ Field injectivity conformance for reservoir pressure support is very crucial as the field is undergoing severe depletions over years and unable to meet the production target. The Operator realized the importance in order to further increase the recovery factor, hence has included ‘B’ field in the Improved Oil Recovery (IOR) project to boost the production and prolong ‘B'field's life. Based on comprehensive IOR/EOR screening study, water injection process has been identified as the most amenable IOR process in ‘B'field. Hence, in Phase 1 drilling campaign, two (2) water injectors were drilled in 2016 in order to achieve the target oil recovery. Both well BWI-01 and BWI-02 were completed with Intelligent completions (IC) and expected to come online in Q4 2018.
This paper further discusses the injection strategy in ‘B’ field multi-zones to meet the zonal injectivity and reservoir zonal voidage replacement requirement for pressure maintenance over field production life. The discussion covers the reservoir characteristics and zonal injectivity challenges with surface constraints that require intelligent completions solution for IOR phase. Completions architecture and customized metallurgy needs is crucial to meet operational challenges. Fit-for-purpose and maintaning development cost is pre-requisite to achieve well injection performance for optimal production