Brownfield in Balingian and Baram Delta have handful of idle wells and well to be abandoned in their inventories. The project aims to reduce the idle well inventories and support production gain through monetizing behind casing opportunities. The target is to appraise and develop LRLC potentials with lower cost of appraisals. This will maximize full field potentials before abandonment and leads to future development of LRLC opportunities as conventional reservoir becomes more difficult to develop.
The idle well inventory has grew up due to problem in production (increase water cut, HGOR) and well problems (sand, fish). An order has been introduced to reduce the idle well list up to 50%. Additionally, in the past, the LRLC intervals were often ignored and considered as water-wet sands due to high water saturation or as tight sands. These intervals, that contain significant reserves, are recognized in many technical papers explaining its identification and evaluation techniques from well-data (logs and samples/cores). The scope of the project is to rejuvenate the idle wells by add-perf LRLC reservoirs.
It is impossible to achieve the target without the presence of proper and improved LRLC BCO evaluation process, thus an integrated workflow approach (between Petrophysicist, Reservoir Engineer, Production Technologist, Asset manager & Well Intervention group) has been developed and applied in the project. A new evaluation tools had also been developed called REM (Resolution Enhanced Modelling) in order to improve the log properties of LRLC reservoirs so that the data obtained from old conventional tools can still be used to evaluate LRLC reservoir. Although LRLC is termed UNSEEN, the risk is reduced by proper understanding of hydrocarbon column and sand development.
To date, 7 fields are already benefitted from this approach. Field A LRLC reservoir for example has tripled the hydrocarbon saturation, and net to gross has improved to 20% using REM compare to 5% without REM. The other 6 fields are also gaining the same increase in the properties. This has resulted in a cumulative potential of 4.4 MMstb of reserves addition and ~11 KBopd potential gain. As a result, a better and attractive BCO proposals can be generated from LRLC opportunities. The exercise will provide the company with cheaper options of appraising and developing LRLC reservoir while reducing the idle wells. There is no better way of understanding LRLC reservoir; as no tools can identify & quantify it yet, rather from the actual production.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
As oil prices are fluctuating, decision makers are challenged to make the "best" decisions for field's developments. Decision Tree Analysis (DTA) can help decision makers to make the "best" decisions. DTA focuses on managerial decisions, such as whether to do workover or not, whether the additional information will be valuable or not. The aim of this work is to review the applications of DTA in petroleum engineering and provide a clear methodology on how to apply DTA for any petroleum engineering application.
The combination of Expected Monetary Value (EMV) and DTA is one of the most common methods used in the decision-making process. If EMV is positive, the decision is considered to be feasible. However, that doesn't mean the decision will be successful at all times. It simply means that if a similar decision is made for a larger number of cases, the decision will be successful. DTA will account for the uncertainty in the probability. A good number of papers about the applications of DTA in petroleum engineering were read and summarized into three categories. Also, a clear methodology on how to apply the DTA for any petroleum engineering application was established.
After reading and summarizing a good number of papers and case histories about the applications of DTA in petroleum engineering, it was concluded that the applications can be classified into three main categories; applications of DTA and EMV for the whole oil and gas prospect projects, applications of DTA and EMV for a specific operation or development, applications of DTA, EMV, Monte Carlo simulations, and other methods to assess the value of information. These applications were summarized into tables.
In addition, a clear methodology accomplished by a flowchart that explains how to successfully apply the EMV and DTA for any petroleum engineering application was provided. The method consists of three main steps: 1) how many scenarios need to be considered and what are they 2) collection of the required data 3) use the visual tool (DTA) or programming to find EMV. Each of the previous steps has its own challenges, thus these challenges were addressed and the solutions to overcome the challenges were provided. Finally, practical guidelines have were developed that when used with the accompanying flow chart will serve as a quick reference to apply the DTA for any petroleum engineering application.
As the petroleum engineering applications becoming more complicated nowadays, accomplished by the oil prices fluctuations, the decision-making processes becoming more difficult. The DTA is a very important tool for the decision makers to make the "best" decision. This paper provides a clear methodology on how to successfully apply the DTA which can serve as a reference for any future DTA applications in petroleum engineering.
Low Resistivity low contrast (LRLC) reservoirs were normally disregarded due to high water saturation and classified as tight sand. LRLC reservoir defined as Pay that has low resistivity contrast between sand and adjacent shale due to presence of conductive mineral or fresh water. Hence, this paper will transform the standpoint by demonstrating values and potential reserve addition underneath LRLC reservoir which proves that it could contribute equally as the conventional reservoir and realizing potential reserve growth.
HY field located in Baram Delta Basin East Malaysia has been producing for more than 40 years and classified as lower coastal plain to coastal environment. The reservoir is loosely consolidated, fine to very fine sandstone and interbedded with shale. Z reservoir (Low Resistivity contrast reservoir) initially identified as gas-bearing reservoir with fresh water salinity of 2k-4kppm. Plus, difference in resistivity values between sand and adjacent shale only separated by ~3ohmm .Due to these claims, there is no Oil interpreted below the gas level and been neglected for years.
A robust water salinity investigation supported with the geological point of view and water sample taken at the wellhead, Project Team proposed the water salinity should be 10k-15k ppm which is more saline than previously assumed. Revision in water salinity value has led to pinpoint Z reservoir as Oil bearing reservoir and recover estimated ~200 ft Pay of Oil column in Z reservoir.
An appraisal well was drilled for data gathering and exploring potential in the deeper sections, hence serve as a platform for further petrophysical evaluation in the Z reservoir. As a result, Project team managed to take Oil sample and Oil gradient for Z reservoir. In addition, PVT lab result showed the oil sample taken having similar fluid property as the produced oil in the major reservoir. Based from the existing static model, potential additional of recoverable reserves was calculated around 20 MMstb for the Z reservoir. This has been an eye opener for the team to give an extra attention and emphasis on the true potential beneath the LRLC reservoir.
Bakar, Hasmizah (PETRONAS Carigali Sdn Bhd) | Watchawong, Dangchin (PETRONAS Carigali Sdn Bhd) | Sahar, Raja Nor Rafidah Raja (PETRONAS Carigali Sdn Bhd) | Saleh, Malaz (PETRONAS Carigali Sdn Bhd) | Muhaimin, Wan Firda Asila Wan (PETRONAS Carigali Sdn Bhd) | Jeffrey, Suzanna Juyanty Mohd (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil (PETRONAS Carigali Sdn Bhd)
During the low oil price period, PETRONAS Carigali Sdn Bhd (PCSB) embarked on an intensified approach to prioritize the production enhancement and idle well reactivation (PE/IWR) activities in its Malaysia operations. To monetize the remaining reserves from these 2,000 active and idle strings, comprehensive opportunity management system which covers opportunity identification, evaluation and prioritization, planning, execution and tracking the activities are implemented. The identified opportunities from the active and idle wells inventory and integrated field review are initially assessed at a high level based on three criteria, value (the estimated Unit Enhancement Cost, UEC), probability of success and doability which indicates how quickly it will be restored. After the due diligence work completed, the opportunities will progress to the multi-disciplinary technical commercial value assurance committee for approval then followed by planning and scoping the detailed execution. All prioritized, approved and planned opportunities are then turned into execution pipeline and properly tracked into a systematic methodology for post job analysis, evaluating the success of the jobs and recording the lessons learnt for improved future jobs is also addressed in this article. This article also outlines the examples of comprehensive and successful approach of idle string reactivation activities which gone through this opportunity management system via fishing operation, scale removal treatment, gas lift optimization, behind casing opportunities, acid matrix stimulation and surface facilities rejuvenation. This approach has significantly improved the percentage of active wells in entire domestic operation from 50 to 53%.
Tran, S. T. (Lamson Joint Operating Company) | Vu, H. V. (Lamson Joint Operating Company) | Le, V. M. (Lamson Joint Operating Company) | Nguyen, T. N. (Lamson Joint Operating Company) | Nguyen, L. H. (Lamson Joint Operating Company) | Prajunla, P. (GE Oil & Gas Inc.) | Dong, H. M. H. (Eastsea Star Company)
Artificial lift technology application in heavy oil production has been a far-reaching development in the industry over past decades guided by persistent efforts to improve the ultimate recovery of this "difficult" hydrocarbon. Heavy oil discovery in a marginal field, Cuu Long Basin, Offshore Vietnam is relatively aberrant and pose challenges to full field development. A series of systematic technical studies has been purposely planned from the first discovery of heavy oil in the wildcat well to the modeling study and facility design to accommodate the viscous fluid over the field life. Apart from the thermal method, pumping technology makes remarkable advance by enlarging the drawdown created over the conventional gas lift in several heavy oil projects. After due consideration, the Electrical Submersible Pump (ESP) was finally decided as the key driver to reinforce well production performance. Moreover, the gas lift has been brought in as a backup in case of pump failure which is not only to prolong well life, save workover expenditure but also boost production if operating in hybrid mode.
This paper presents sequential events from the conceptual study to pilot test hybrid ESP/Gas lift system and ultimately the inflow/outflow curves analysis. A proper system analysis of the inflow/outflow curves is indispensable to model the outflow curve above the pump where the aid of gas lift complicated the upward flow and to generate the lift curves used in reservoir simulation. The pilot test of this electro-gas system to Well A has shown about 30% liquid production increment with lesser pump energy consumed and flexibility in control operating point. The early results promise further extension to the remaining ESP wells to enhance field production.
Malaysia's oilfields production are mostly in a declining trend but the remaining oil left is still significant with an average of oil recovery factor of less than fourty percent, 40%. In arresting this phenomenon, PETRONAS has taken proactive steps to ensure the sustainability and growth of oil production to be inlined with the projected demand and supply outlook for the next five to ten years timeframe. As such, one of major steps taken is looking into Enhanced Oil Recovery (EOR) technique to increase further field recovery factor by improving sweep efficiency of the reservoir for fluids displacement enhancement. Several EOR techniques were put on focused in ensuring target value of sweep efficiency is meeting both macro and micro efficiencies closer to one. Amongst the focus steps are, EOR screening process identification, laboratory work and high order of three dimensional (3D) simulation study. This paper will discuss how displacement test techniques for EOR water alternating gas (WAG) are able to quantity macro and micro sweep parameters at heterogenoues conditions, namely hysteresis; alpha, a, and C. Subsequently, translating it into field 3D simulation study e.g. validation of laboratory result in relationship with relative pemeability modification (imbibition and drainage curves) to quantify the EOR WAG potential. With this, PETRONAS has established a robust techniques for the EOR WAG hysterisis process from laboratory to field application in the context of Malaysia's EOR WAG hysterysis methodology. To-date, the developed processes of WAG hysteresis is proven by first production achieved in year 2014.
Nowadays as majority of giant hydrocarbon fields are in their late development phases consequently project teams are looking for a way to extend the field life economics using a proper approach. In such a case having a much robust reservoir model would be a great favor to reduce the risk and uncertainty of EOR/IOR plans. Successful development plan for the marginal project is highly controlled by the validity of conceptual model particularly where the complex structure or lithology components exist such as effective clay minerals and low saline water (in or ex -situ). In this study, it is focused on one of the EOR target reservoirs in Baram Delta which has significantly produced over 40 years. The main objective of this study is to characterize the variation of swept leg’s reservoir properties when the low saline formation water exposes to the clay reach oil bearing intervals. The combination of different data sources such as nuclear magnetic resonance measurement, existing core data and invasion profiles together with conventional logs have been utilized to quantify the behavior of flow paths before and after water exposure. The results demonstrate the interaction between formation water and lithology components has no major impact on total porosity but there are drastic changes on pore geometry particularly on pore size distribution and tortuosity of the flow path. The most negative impact has been introduced to the reservoir permeability since it is highly controlled by the pore geometry. At the field scale both injectivity performance and sweep efficiency have been significantly affected by changing the ideal flow path and connectivity at the target sands. Eventually, an empirical equation was developed to characterize the magnitude of the damaged as the function of pore geometry. The result is expected to be used as an optimization algorithm to minimize the risk of upcoming development plan while it provides a better understanding of the real mechanism of fluid flow, uncertainty of the reservoir model, and performance of EOR plan.
Formation water content is one of the key petrophysical quantities provided by dielectric logging. However, to determine water content from formation permittivity measurements, the rock matrix permittivity must be known. Uncertainty in the rock matrix permittivity values translates into uncertainty in the water-content estimate,which is especially important in low-porosity formations or complex lithologies. Matrix permittivity values are not well-known for a number of minerals and can also vary for the same type of mineral in different formations. Thus, a laboratory methodology for the accurate determination of matrix permittivity at dielectric logging frequencies is required to facilitate accurate log interpretation. One can measure matrix permittivity values on solid plugs (Seleznev et al. 2011). However, the plug-based methodology can be challenging in very-low-permeability or unconventional reservoirs because of difficulties with plug drying. In addition, it is not readily applicable to unconsolidated formations. Finally, it may be impossible to cut solid plugs because of limited availability of rock material. Matrix permittivity measurements made on rock powders are capable of addressing all these issues. We introduce a methodology for laboratory measurements of matrix permittivity on rock powders at 1 GHz. The methodology is based on conducting dielectric measurements on mixtures of rock powders and liquids with variable permittivities in a dielectric resonator. The permittivity of the rock matrix is inverted from a series of measurements obtained on pure liquids and powder/liquid mixtures. The methodology was benchmarked on a collection of samples representing common oilfield lithologies with matrixpermittivity values between 4.6 and 8.6. The reference matrixpermittivity values were first measured on solid plugs. Then, the plugs were crushed into powders, and the matrix permittivity values were determined on powders following the proposed methodology. The values obtained on powders matched the ones measured on solid plugs within 0.2 dielectric units, resulting in accuracies better than 1% for the water-filled porosity and better than 1,000 ppm for water salinity. This new methodology was applied to a number of core samples from a carbonate reservoir offshore Sarawak, where dielectric logging was performed along with conventional core analysis. The resulting measured matrix permittivity values were then used to interpret the dielectric log measurement. Results showed a better estimation of water-filled porosity and of the textural MN parameter, equivalent to the Archie’s cementation exponent in a waterbearing zone, than would have resulted from using “chartbook” values of matrix permittivity. A consistent and optimized interpretation was obtained in porosities ranging from 5% to more than 30%.
A. R. Almeida, Petrobras Research and Development Center Summary The Venturi valve represents a significant advancement in the technology of gas lift in petroleum wells. Its use is expanding, and an understanding of the theoretical and practical aspects is fundamental to maximize the benefits of its application. The application-related aspects are reasonably well-covered in the literature; however, to achieve good performance and promote the expected benefits, some valve-design aspects have to be taken into account. Introduction The Venturi-nozzle (or simply Venturi) gas lift valve is being used increasingly in continuous gas lift wells worldwide. Some articles (Tokar et al. 1996; Faustinelli et al. 1999; Lyngholm et al. 2007; Kartoatmodjo et al. 2008; Almeida 2010, 2011a, 2011b; Rilian et al. 2012) describe aspects of this technology. In Brazil, approximately 350 offshore wells are now equipped with these valves and more than 600 valves with Venturis were run in wells or tested by Petrobras. Roughly speaking, there are two types of gas lift valves. In the first type, there is some sort of mechanism to open or close the valve according to pressure (and, in most cases, temperature) conditions in the well. A charged bellows is the most-used mechanism. The second type involves valves that are always open (in the casing-totubing direction).
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.