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.
Kartawijaya, Ian Adrian (BP Indonesia) | Menanti, Yoseph (BP Indonesia) | Saraswaty, Dhita (BP Indonesia) | Suganda, Singgih (BP Indonesia) | Iqbal, Muhammad (BP Indonesia) | Anantokusumo, Ferry (BP Indonesia) | Dinata, Randy Chandrana (BP Indonesia)
Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations.
Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter.
Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance.
First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate.
Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve.
Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.
Zhang, Guoqiang (China National Offshore Oil Corporation, Ltd. Tianjin Branch) | Tan, Zhongjian (China National Offshore Oil Corporation, Ltd. Tianjin Branch) | Hao, Zhongtian (China National Offshore Oil Corporation, Ltd. Tianjin Branch) | Fan, Zhao Ya (Schlumberger) | Chen, Ji Chao (Schlumberger) | Gao, Bei (Schlumberger) | Shelomikhina, Irina (Schlumberger) | Zhang, Tao (Schlumberger)
The new gas condensate has been discovered recently in Bohai Bay China, and due to the complex of the fluid behaviour in nature, appropriate characterization of the in-situ fluids and relevant flow testing can provide valuable insight into gas condensate reservoir forecasting. This paper discussed a comprehensive methodology for reliable productivity evaluation with the aid of in-situ fluid characterization and interval pressure testing, and its results as a key factor not only fed into DST design and equipment optimization for better production evaluation design but also can be optimal production prediction for reserve booking. Based on the efficient and reliable productivity evaluation, we can make the real-time decision on whether to carry on DST and which DST equipment should be chosen and where to test it. However, we has been dealing with heavy oil for very long time, and the common DST equipment in Bohai Bay is not designed for condensate reservoir, but heavy oil, plus there were no published case studies in China about DST modification from heavy oil to gas condensate, and what can be done for production forecasting in gas condensate reservoir. In this paper, a new solution was proposed base on the problem elaborated above. An integrated approach was conducted to overcome challenges by using all available data from Wireline Formation Tester (WFT) and conventional log data. An accurate permeability is always the foundation of a good prediction, a single well model was built by taking full advantage of all permeability information; Compositional model is the best way to simulate the condensate phase change, in this paper, a calibrated composition was deduced by combining with semi-quantitative DFA composition and PVT analysis software (PVTi) via calibrating downhole measured GOR and density; Black oil model is the most common and popular method to evaluated single well productivity, but the uncertainty of condensate viscosity usually leads huge error, based on the calibrated composition results, evaluated the downhole fluid viscosity, after downhole fluid viscosity correctly evaluated, black oil model can also be applied in condensate productivity evaluation. DST results were used to validate the results from this approach, the error percentage range is around 10% compare with DST results. This new solution has following values: an accurate gas condensate production forecast become possible even without PVT lab results.
Acid stimulation is an excellent method to increase hydrocarbon production and long-term formation drainage from carbonate formations. However, the stimulation effectiveness largely depends on pertinent placement method. Besides the necessity for optimized treatment design and fluid recipe, homogenous acid distribution is one of the most critical aspects for treatment success. For this purpose, a novel completion method has been deployed that allows for effective acid stimulation by maximizing formation contact in the openhole horizontal wellbore.
An improved Multistage Stimulation System (MSS) that has been developed to distribute acid homogenously across the lateral is utilized, where multiple sleeves are deployed in clusters as part of a single stage, and opened with a single size ball without being limited to pump rate. It was considered imperative to have positive indications of the balls landing on the seats and the sleeves being shifted open within the zone of interest. The previous MSS system was based on severing part of the nozzles for fluid access which needed to be upgraded for better operational efficiency and production enhancement.
The new completion technology is suitable for carbonate formations which are tight, heterogeneous and require stimulation to improve gas production and recovery. Wells drilled in the maximum horizontal stress direction to mitigate hole stability risks and geosteered to maximize the formation contact makes it difficult to stimulate effectively. Therefore, an improved MSS system is required to homogenously distribute the acid across the lateral during the stimulation. This novel MSS completion design was undertaken standardized, well established trial test procedure and was applied in a candidate well and included three stages where two of the stages utilized four sliding sleeves while the remaining stage was integrated with five sliding sleeves. Each stage was isolated by hydro-mechanical packers in the 5.875 in openhole.
Each stage was then monitored using a new surface mounted real-time downhole monitoring system, an electronic device that enables live verification of completion operation events while being independent of pressure. The data gathered from different sources indicated that the sleeves functioned as per design. The production results exceeded the expectations.
This paper describes a novel approach that enhances acid stimulation effectiveness and fulfills stimulation objectives using advanced openhole MSS completion technology. Evolution of the technology and comparison with its predecessor is discussed. It also demonstrates the use of a new surface monitoring system that supplies real time data during sleeve activations enabling clear and accurate detection of downhole events.
This paper discusses how the pressure measured by the downhole gauges during a drillstem test (DST) is affected not only by hydrostatic, friction, or kinetic-energy pressure losses, but also by changes in temperature. In oil wells, the bottomhole temperature is decreasing when the pressure is building up after a flow period. The change in temperature is inducing a change in the wellborefluid density, itself affecting the bottomhole pressure. Most numerical-simulators modeling flow in pipes do not take into account this effect, because it is not significant for low- to moderate-productivity wells. In high-productivity wells, however, the temperature change can affect dramatically the bottomhole pressure measured above the reservoir, and the pressure can even decrease at the end of a static period. A mathematical model is presented to compute the pressure drop caused by the nonisothermal effects, and it can be used to correct the measurements. Field examples are discussed to illustrate this effect, and recommendations are made on how new technology can improve pressure measurements during well tests.
To measure the effects on the pressure measurements caused by the position of the gauges in the DST string, two gauge carriers were run in some well tests in deepwater wells offshore Brazil, one at the level of the tester valve and one below the packer, as deep as possible in the test string. The gauges could transmit data with a wireless telemetry system that allowed the operator to monitor in real time the pressure changes and the difference between the two sets of gauges.
In high-permeability wells, using the uncorrected pressure measured with a gauge 50 to 100m above the reservoir, as is typically the case, can result in a wrong productivity index (PI) and, at times, in uninterpretable results. Locating pressure gauges as close to the reservoir as possible is crucial in high-permeability reservoirs, to minimize the measurement errors, but also to avoid misinterpretations when an obstruction forms below the tester valve. With the new wireless telemetry systems, it is possible to monitor in real time gauges mounted below the packer, much closer to the perforations than the standard gauges placed at the level of the tester valve, thus avoiding making wrong decisions during the test.
A long pressure-transient test could be uninterpretable because the gauges are at the wrong depth. Ideally, the pressure gauges should be placed in front of the perforations, but it is not always possible. Therefore, nonisothermal effects on pressure measurements during a well test need to be clearly understood and taken into account when designing and interpreting well tests, particularly in high-productivity reservoirs.
Al-Shammari, B. (Kuwait Oil Company) | Rane, N. M. (Kuwait Oil Company) | Desai, S. F. (Kuwait Oil Company) | Al Sabea, Salem Hamad (Kuwait Oil Company) | Pandey, M. (Weatherford) | Shankhdhar, S. (Weatherford) | Chacko, R. (Weatherford) | Ledesma, F. S. (Weatherford)
Kuwait Oil Company started implementing digital oil field technology in 2009, with a vision to achieve integrated operations for measurement, modeling and control of Burgan oil field production. The project involved development of automated workflows connecting real-time data and integrated production models for analyzing asset performance and identifying production optimization opportunities. The workflow calculates variance in daily field production and correlates it to the corresponding well production change alerts attributed to key changes in well and facility parameters. Well health status is determined using key performance parameters and subsequently wells are categorized for planning remedial actions. The workflow further utilizes the integrated surface network model in an automated process to generate production optimization opportunities under various well and plant operating limits and the results are visualized through interactive dashboards in a state-of- the-art collaboration center for quick analysis.
This paper discusses the application of smart workflows for analyzing asset performance and recommending production optimization actions in Burgan oil field. It describes how smart workflows are used to integrate real-time well and facility data with production models to assist the operator in faster diagnostics and improved decision making.
The paper demonstrates through field examples how the application of an automated workflow using real-time data and integrated models has improved the conventional approach for asset performance analysis and optimization resulting in significant cost savings for the operator.
Kulananpakdee, K. (PTTEP) | Chommali, P. (PTTEP) | Hien, N. (PTTEP) | Thiangtham, C. (PTTEP) | Juntamat, P. (PTTEP) | Lertsrisunthad, P. (PTTEP) | Prachukbunchong, P. (PTTEP) | Chantipna, D. (Weatherford) | Pinprayong, V. (Weatherford) | Villamizar, C. (Weatherford) | Baca, Espinoza I. (Weatherford)
Determining reservoir pressure and confirming fluid type in development wells is of major interest to many reservoir engineers. Because of the high costs and operational risks of having a wireline formation tester (FT) stuck downhole, operators seek reliable technologies that not only deliver the information they need but also mitigate the chances of losing the tool downhole. A new generation of slim, light-weight FT technologies can help make production-management decisions, especially in the often complex geometry of development wells.
The Sirikit field Onshore Thailand is an extensively faulted and heterogeneous reservoir, therefore continuously updated pressure profiles have become the key in refining reservoir models. Productive zones are typically thin, but highly permeable. Traditional open hole (OH) log evaluation is insufficient to distinguish fluid types and formation fluid identification (FID) is required in every zone before completion. Because wireline FTs often have thick bodies which are pressed against the borehole wall and sampling takes at least one hour of pump out, they present an increased risk of getting stuck.
A smaller diameter FT was evaluated whose body equally centralized in the well during a test in order to dramatically reduce the risk of differential sticking. However it was not clear whether the new tool could similarly distinguish between hydrocarbons and water in a synthetic based mud (SBM) environment using capacitance and resistivity sensors. Four wells with various trajectories and fluid types were selected to benchmark the new tool. Both traditional and new slim FTs were run in the hole (RIH), monitored in real time and the capabilities of the two tools were cross-checked against each other. The results showed that both tools required a similar pump out volume to reach a clean sample. Despite the oil-base mud environment, the slim tool was able to distinguish the transition from mud filtrate to formation hydrocarbons, and in wells where water-base drilling fluids were used, formation water could be similarly recognized. All water samples were directly drained at surface to verify the in-situ real time measurements and oil samples were sent to the lab. The results showed a remarkable consistency in most cases and during trial tests the slimmest sampling tool exhibited a tremendous value in the first stage of field development and it is continuously used nowadays in newly drilled wells.
A slim testing and sampling tool shows good reliability for basic fluid identification and is especially suitable for wells with differential sticking issues. Globally, this tool may provide a solution of future wireline pressure and sampling, which can help operators to make proper reservoir-management decisions, especially in complex geometry wells or challenging geological formations.
This case study reports a comprehensive sanding study program for two offshore gas-condensate fields. The results from geomechanics laboratory testing and modeling of sand production were implemented into real-time monitoring of production wells using the Production Data Management System (PDMS). Sand detectors were also instrumented on all production wellheads and integrated into the real-time monitoring. The program will help define the envelopes of optimized production while ensuring safety of production facilities.
Comprehensive geomechanics laboratory testing was conducted on reservoir cores retrieved from exploration and production wells. In addition to unconfined compression tests and TWC tests, the testing included triaxial tests with acoustic velocities during hydrostatic confinement as well as deviatoric axial loading to determine formation rock strength and deformation behaviors. The laboratory results were then used to calibrate strength and elastic properties logs used in sand production modeling. Optimized production envelopes for each well could then be determined. Finally, the modeling results were integrated into PDMS so that downhole gauge pressure and sand detector readings could be monitored and managed real-time for all production wells.
The results revealed that many reservoirs in Hai Thach and Moc Tinh fields have relatively low strength and therefore moderate sanding potential. This study would help define the envelopes of optimized production while ensuring safety of production facilities. These envelopes included sanding prevention criteria in addition to criteria to optimize condensate production and minimize water production. Regarding sand production, downhole gauge pressure are monitored real-time and managed so that drawdowns are below sand production threshold at current reservoir pressures. The key functionality goal is real-time collaboration between onshore and offshore to establish reliable information for reservoir monitoring, improving modeling, and production losses mitigation, which significantly improves production through a proactive well management.
Ramizah, A. R. (Schlumberger) | Gordon, Goh K. F. (Schlumberger) | Tina, Lee L. T. (Schlumberger) | Varma, G. (Schlumberger) | Muzahidin, M. S. (Schlumberger) | Willem, S. (Schlumberger) | Ahmad, S. H. (Schlumberger) | Sanggeetha, K. (Schlumberger) | Lester, T. M. (Schlumberger) | Khairul, Akmal M. (Petronas) | Mabel, Chia P. C. (Petronas) | Tamin, M. (Petronas) | Dipak, M. (Petronas)
Upfront investment and capital commitment is required in installing Intelligent Completion (IC) in ‘S’ Field. Without diligently using real-time sensor data, IC becomes an expensive Sliding Sleeve Door (SSD). A real-time surveillance and analysis tool was developed to maximize IC zonal control decision-making for commingled production optimization. It enables user to utilize fully the hardware to improve production and to extract production and reservoir information for subsequent Enhanced Oil Recovery (EOR) workflow input. The analysis platform connects to real-time data source and performs calculations converting sensor data into knowledge [i.e. zonal flow rates, productivity index (PI) and reservoir pressure (P*)] and intelligence (i.e. zonal production optimization). User will spend minimal time on data gathering instead maximum time optimizing production by analyzing the trending and diagnostic plots.
IC is surface controllable multi-position zonal downhole sensors that read tubing and annulus pressure, tubing and annulus temperature and flow control valve (FCV) positions. ‘S’ Field installed IC in nine wells and is in the late production life of initiating an EOR multi-zone production optimization. However, under-utilized sensor data and trial-and-error zonal-control method led to suboptimal response time, production delay and reactive mitigation action. Furthermore, there are persistent difficulties of integrating multi-zone downhole sensors with surface well-test data in a single analysis platform to improve production or reduce watercut.
This paper will outline how the integrated analysis platform will help both operational and subsurface team in making faster and guided decision to maximize the reservoir recovery in an Enhanced Oil Recovery (EOR) Integrated Operation IO. The tool was developed and tailored to complement IC installation in maximizing zonal control decision-making and zonal performance monitoring, specifically for commingled production. It is a customized solution to utilize zonal IC downhole data to enable field-wide EOR performance monitoring and trending advantages in ‘S’ Field EOR project.
Choudhary, Manish Kumar (Brunei Shell Petroleum Sdn. Bhd.) | Lai, Suan-Loong (Brunei Shell Petroleum Sdn. Bhd.) | Sahu, Sambit Kumar (Brunei Shell Petroleum Sdn. Bhd.) | Arfie, Mezlul (Brunei Shell Petroleum Sdn. Bhd.)
Brunei Shell Petroleum (BSP) encompasses multiple offshore and onshore oil and gas field. The study asset produces more than 50% of company's hydrocarbon production. Currently, gas production from the asset is at maximum system limit governed by downstream gas demand and surface-facility constraints. Producing the wells at right configuration can help in maximising condensate production while honouring gas demand thereby maximising revenue for the asset.
The analysis of data from past few months indicated that actual condensate production was quite lower than asset-wide Integrated Production System Model (IPSM) estimates. Frequently, wells were operated in wrong configuration which had resulted in system/wells operating outside Operating Envelopes (OE's), excessing choke wears, system trips and higher production deferment. A production optimisation study using LEAN approach was initiated to maximise condensate production and to increase process safety compliance.
Multiple brainstorming sessions were organized to map data flow from well-testing to production optimization to offshore operations. The process map highlighted that scheduled activities, operational requirement and communication issues often resulted in well configuration different than IPSM suggested configuration. The LEAN approach helped in identifying system wastes, viz. absence of real-time feedback to operators, different tools/software used by different team, reaction time to new testing data, misunderstanding of well OEs etc. which were resulting in lower condensate production.
A fit-for-purpose Real Time Optimization (RTO) tool was developed which used pressure and flow data from wellhead sensors and from real-time production estimation tool (viz. Production Universe) to generate best configuration of wells for maximising revenue. The optimum configuration accounted for well and facilities OE ensuring better process safety compliance. The tool output could be compared against real-time measures (e.g. Tubing head pressures) and providing continuous feedback to operators.
The RTO tool was implemented in Q2 2016 with full support of asset leadership. Multiple offshore trips were made to explain the tool to frontline operation staff, operation supervisors and production leads. The project helped in increasing condensate production by over 20% and created a reliable and sustainable process for continuous optimization directly by operations staff. It also ensured that wells always produced within OEs thereby increasing process safety compliance. Operating the wells and chokes optimally also led to cost savings from reduced choke replacements and lower production deferment. The tool served as a common reference for all teams thus eliminating communication waste.
The use of real-time sensors and Production Universe and RTO can help in reducing reaction time to system changes and help in maximising revenue. A sustained and integrated effort is needed to drive the process in the organisation and achieve production gain. The LEAN process can be useful to in root cause identification of problems and for drafting mitigation measures.