Day 1 Tue, October 12, 2021最新文献

{"title":"Managing Gas Well Blowouts: Case Studies from Assam-Arakan & Krishna-Godavari Basin","authors":"R. Bharadwaj, Bhavya Kumari, Astha Patel","doi":"10.2118/206602-ms","DOIUrl":"https://doi.org/10.2118/206602-ms","url":null,"abstract":"\u0000 E&P activities are the early stage of energy production and pivotal for generating and sustaining economic growth. However, negligence and evaluating the circumstances incorrectly during these operations can lead to calamities like blowouts. This paper discusses two such tragedies, the Pasarlapudi (Krishna-Godavari) Gas Well Blowout of 1995 & Baghjan (Assam-Arakan) Oil Field Blowout of 2020, and provides possible well control measures and lessons learned.\u0000 Pasarlapudi blowout incident occurred during the drilling operations. The pipe stuck-up situation at 2727m MD (Measured Depth) was detected by conducting a stretch test. Further analysis could include circulating brine, checking lost circulation and identifying casing leaks by measuring Sustained Casing Pressure (SCP), Operator-imposed Pressure (OIP), and Thermal-induced Pressure (TIP). Baghjan's gas well at the depth 3870m was producing at 2.8-3.5 MMSCFD. The aim was to plug the lower producing zone and recomplete the well in the upper Lakadong+Therria sand zone. Well was killed using brine, cement plug was placed and BOP installed. BOP was removed after the plug was set to begin the process of moving the workover rig. Well blew gas profusely during this process.\u0000 Simulating a blowout and facing one, are two completely different situations. In Pasarlapudi's case, the well blew with an enormous gas pressure of 281.2 ± 0.5 kg/cm2. While drilling the production hole (8.5 inch), either differential pressure sticking, presence of water-swelling clay formation or the partial collapse of wellbore formation caused the pipe stuck-up situation. By conducting stretch test along with circulating brine, root cause of this problem could be identified. If differential sticking occurred, lost circulation could be checked & cured, while keeping the hole full. Circulating brine should solve the problem of swelling clay formation while formation collapse could have occurred due to the presence of plastic formation like salt domes.\u0000 In the case of Baghjan gas well blowout during workover operations, probable safety measures could include placement of 2 or 3 backup cement plugs along with kill fluid or going for squeeze cementing before placing the cement plug & kill fluid while abandoning the lower producing zone. Attempts were made to bring the well under control by adequate water spraying, installing BOP. Water was pumped through the casing valve and a water reservoir was dug near the well plinth for the placement of pumps of 2500 gallon capacity.\u0000 Proper safety measures should be used even when they're not the cheapest to avoid repetition of treatments and detrimental situations. SCP, OIP and TIP should be measured periodically whenever possible and the root cause of situations like lost circulation, pipe stuck-ups, kicks, casing leaks should be identified before proceeding towards drastic remedial operations. Innovations in countering well-control situations should be promoted invariably.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91523071","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A 3-Step Reaction Model For Numerical Simulation of In-Situ Combustion","authors":"Allan Rojas, C. Yuan, D. Emelianov, E. Saifullin, S. Mehrabi-Kalajahi, M. Varfolomeev, V. Sudakov, Bulat R. Lotfullin, D. Shevchenko, B. Ganiev, A. Lutfullin, A. Zaripov","doi":"10.2118/206430-ms","DOIUrl":"https://doi.org/10.2118/206430-ms","url":null,"abstract":"\u0000 In-situ combustion (ISC) is an effective thermal enhanced oil recovery method. However, it is still not widely implemented in oilfields. One of the factors limiting the wide application of ISC is the challenge in its simulation and prediction. In this work, the oxidation experiments of maltenes and asphaltenes in reservoir rock were performed in the porous media thermo-effect cell (PMTEC) to establish a simplified reaction model based on non-isothermal measurements and to use it in numerical simulation of ISC process. It was found that the oxidation reaction process of oil fractions can be divided into different regions depending on generated self-energy rate and oxygen consumption rates that is up to the temperature. In order to propagate reactions from one mode to another, a specific oxygen consumption per unit mass of oil fractions is required. The average oxygen requirement for crossing LTOad (low temperature oxidation, oxygen addition reactions) boundary into LTC (low temperature combustion) mode was 64 mgO2/g(maltenes) and 10.4 mgO2/g(asphaltenes). To propagate reactions into HTO mode from the LTC mode, it requires about 646 mgO2/g(asphaltenes) for asphaltenes fraction. Moreover, this characterization seems to be a key tool when designing air injection in field pilots. Additionally, it was revealed that asphaltenes are more exothermic and require lower oxygen uptake per unit of temperature increment in comparison to maltenes. Furthermore, the mass conversion data obtained from non-isothermal measurements of oil fractions allow for the estimation of the stoichiometry coefficients of two low temperature oxidation reactions, i.e. oxidation and cocking processes, which can be included into a numerical simulation model to replicate combustion tube (CT) results. The numerical simulation model reveals that the simplified reaction model from a 6-step into a 3-step reaction scheme can reproduce ignition process, temperature profiles, combustion velocity, and fluid production, which thus makes it suitable for the upscaled modelling of ISC.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74054822","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Environmental Monitoring and Control Over Production Wells Using Automated Control and Regulation Systems for Orenburgskoe Oil and Gas Field","authors":"Yu. A. Rogov, K. Rymarenko, Alexei Mironositskii, S. Grishenko, A. Golubtsov, V. Kabanov, Tatyana Gusachenko, M. Nukhaev","doi":"10.2118/206604-ms","DOIUrl":"https://doi.org/10.2118/206604-ms","url":null,"abstract":"\u0000 Environmental stability and safety are becoming increasingly important in the world. Used to be mainly until recently under state control, the release and distribution of hazardous substances, wastes, and by-products is now monitored and regulated everywhere by enterprises, forced to establish special services that record and transmit information in the dispatch centers of the MES and other regulatory authorities of the Russian Federation. All the measures taken in this respect focus on safety improvement, ensuring occupational safety and accident prevention at enterprises, and safety of people, animals, and natural environmental location, which can be exposed to harmful and dangerous anthropogenic and natural factors.\u0000 Aiming to provide a comprehensive solution to the problem, the authors proposed the concept of environmental monitoring and control over oil and gas wells using automated control and regulation systems and presented the concept on the example of the Orenburgskoe oil and gas condensate field","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82213693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Remote Bed Boundary Detection Tool Data Interpretation Without Special Geosteering Support to Drill Horizontal Wells","authors":"D. Nazipov, P. Shpakov","doi":"10.2118/206631-ms","DOIUrl":"https://doi.org/10.2118/206631-ms","url":null,"abstract":"\u0000 Today, one of the most modern and successful geosteering methods in terms of net to gross value (NTG) is a proactive geosteering.\u0000 The purpose of this article is to share the experience of using Remote Boundary Detection Tools to solve various geological problems and describe the ways of using the data from it.\u0000 The method provides the ability to detect the approaching boundary (usually reservoir top) with resistivity contrast before entering it with the bit or BHA sensors. It allows to adjust well trajectory proactively and, therefore, increase Net to gross ratio.\u0000 The article shows the ways to implement global experience in horizontal wells drilling and proposes ways to reduce the cost of well construction without elimination of High-Tech equipment in BHA.\u0000 The article explains the methods of interpreting the output data from the tool that can determine the approach to one or several boundaries with resistivity contrast.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75103853","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Efficiency of Using a Proxy Model for Modeling of Reservoir Pressure","authors":"E. Yudin, N. Markov, V. Kotezhekov, Svetlana O. Kraeva, A. Makhnov, N. Trubnikov, L. Gorbushin","doi":"10.2118/206553-ms","DOIUrl":"https://doi.org/10.2118/206553-ms","url":null,"abstract":"\u0000 The presented paper is devoted to the development and testing of a computational tool for assessment of the reservoir pressure and prompt generation of the pressure maps of collectors. The tool is based on a proxy model that allows to solve the two-dimensional diffusion equation for unsteady liquid filtration using the boundary element method. To expand the applicability of the proxy model, an algorithm for automated parameter adaptation was developed. This algorithm allows to exclude knowingly unreliable data or low-quality data from modeling. This is achieved due to analyzing the correlation between the injection, production and bottom-hole pressures for the entire well stock over the history of the reservoir development. In addition, this paper describes an approach to modeling two-phase oil and gas filtration based on the use of pseudofunctions. This approach considers the influence of gas on the oil filtration process. The use of pseudofunctions allows us to linearize the diffusion equation for two-phase filtration and to solve it using the boundary element method in the same manner as for the case of oil filtration without gas. To demonstrate the results of the proxy model validation, examples of its use for generating the pore pressure maps for two real collectors are given. The average values of the reservoir pressure at the wells calculated using the proxy model are compared with the results of the corresponding well tests and with the traditional isobar maps. The analysis showed that the average deviation of the proxy model from the real reservoir pressures is less than 10%.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79348499","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Efficiency Criteria of Operations in the Marine Resuce Support for Hydrocarbons Production and Transportation in the Arctic Zone of the Russian Federation","authors":"T. Lapteva, L. A. Kopaeva, M. Mansurov, Vladimir Ivanovich Efremov, Viktor Nikolayevich Ilyuhin","doi":"10.2118/206605-ms","DOIUrl":"https://doi.org/10.2118/206605-ms","url":null,"abstract":"\u0000 The creation of an effective system of rescue support (the abbreviation ASO is adopted on the territory of the Russian Federation) in the implementation of the processes of oil and gas production and transportation in the Arctic seas of Russia is an urgent and difficult task. The feasibility of creating such a system for offshore oil and gas production facilities is due to the statistics of accidents and incidents at such facilities, as well as the fact that the Merchant Shipping Code of the Russian Federation, in essence, does not consider the applicability of the existing system of rescue operations on platforms that are exploring and developing mineral and other non-living resources the seabed and its bowels.\u0000 The successful solution of numerous problems of rescue support, including the requirements for the quality of the system, indicators and criteria for the effectiveness of the operations carried out, can be significantly increased by using mathematical models that make it possible to identify patterns in the processes of performing urgent work, improve the quality of planning, and, consequently, the efficiency of management of various organizational systems. Applied in many areas of activity, the scientific direction \"research of operations\" is advisable to use when system generation of rescue support within the framework of improving the system of technical regulation of oil and gas enterprises.\u0000 Determining the effectiveness of a purposeful process quantitatively will allow, on a scientific basis, with the involvement of modern mathematical methods, to solve the problem of increasing the effectiveness of the use of forces and means of the marine rescue support, including the functioning of the emergency support system in the mode of daily and emergency activities, as well as the preparation of the necessary forces and means.\u0000 The novelty of the presented work lies in the application of the provisions of the theory and the apparatus of operations research to assessing the effectiveness of the system of the marine rescue support, which will further serve as a methodological basis for the development of a number of documents and provisions that are of practical importance: methods, requirements for the system of rescue support, documents in the field of control over the rescue system, etc.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85770824","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Successful Reservoir Fluid Characterization and Testing While Overcoming the Challenges of Falling Oil Price and a Pandemic: A First for an Integrated Brown Field Alliance Project in Sarawak, Malaysia","authors":"Muhamad Aizat B Kamaruddin, Muhammad Haniff Suhaimi, Firdaus Azwardy B. Salleh, N. Hardikar, N. Nathesan, Hilarion Millan, Fadzilazri Shapiei, Manh Hung Nguyen, Ivan Y. Nugraha Putra, Jos Pragt, Olufemi A. Adegbola, Adnan Ibrahim Khan","doi":"10.2118/205778-ms","DOIUrl":"https://doi.org/10.2118/205778-ms","url":null,"abstract":"\u0000 A brown field, offshore Sarawak, Malaysia, with multiple sub-layered laminated sands of varied pressure regimes and mobility ranges, was challenged by depletion, low mobility and uncertainty in the current fluid types and contacts. Optimal dynamic fluid characterization and testing techniques comprising both Wireline and Logging While Drilling (LWD) were applied in nine development wells to acquire reliable formation pressure data and collect representative fluid samples including fluid scanning. Some of the latest technologies were deployed during the dual crises of falling oil price and the Covid-19 pandemic.\u0000 The S-profile wells were drilled using oil-base mud (OBM) with an average deviation of 60 degrees. Formation Pressure While Drilling (FPWD), Fluid Sampling While Drilling (FSWD) and wireline formation testing, and sampling were all utilized allowing appropriate assessment of zones of interest. Various probe types such as Conventional Circular, Reinforced Circular, Elongated, Extra-Elongated and Extended Range Focused were used successfully, ensuring that the right technology was deployed for the right job. Formation pressure and fluid samples were secured in a timely manner to minimize reservoir damage and optimize rig time without jeopardizing the data quality. As a classified crisis due to the pandemic, rather than delaying the operations, a Remote Operations Monitoring and Control Center was set-up in town to aid the limited crew at rig site.\u0000 A high success rate was achieved in acquiring the latest formation pressure regimes, fluid gradients, scanning and sampling, allowing the best completion strategy to be implemented. With the selection of the appropriate probe type at individual sands, 336 pressure tests were conducted, 44 fluid gradients were established, 27 fluid identification (fluid-id / scanning) pump-outs were performed, and 20 representative formation fluid samples (oil, gas, water) were collected. Amongst the Layer-III, Layer-II and Layer-I sands, Layer-I was tight, with mobility < 1.0 mD/cP. Wireline focused probe sampling provided clean oil samples with 1.4 to-3.7 wt. % OBM filtrate contamination. The water samples collected from Layer-II during FSWD proved to be formation water and not injection water. The wells were thus completed as oil producers. Reliable fluid typing and PVT quality sampling at discrete depths saved rig time and eliminated the requirement of additional runs or services including Drill Stem Testing (DST).\u0000 This case study has many firsts. It is the first time where latest fluid characterization and testing technologies in both Wireline and LWD were deployed for an alliance project in Malaysia and that too during dual crises of falling oil price and the pandemic aftermath. Overcoming various challenges including limited rig site manpower, there was no delay in completing the highly deviated wells with tight formations in a single drilling campaign and provided rig time savings.\u0000 For the purpose of t","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80389568","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"First Application of Non-Coiled Tubing Cement Packer Solution in the Region: A Game Changer in Revolutionizing an Enabling Solution During Low Price Environment","authors":"Ahmad Uzair Zubbir, Hani Mohd Said, Muhammad Abdulhadi, Evelyn Ling, Paul Sanchez, Nazri Nor, Nurhanim Ismail, A. M. Ismail","doi":"10.2118/205719-ms","DOIUrl":"https://doi.org/10.2118/205719-ms","url":null,"abstract":"\u0000 Cement Packer is a cost-effective alternative to workover for monetizing hydrocarbon reservoirs above the well top packer. While conventional cement packer utilizes coil tubing for cement placement, an innovative and more cost-effective approach was successfully implemented with only slickline and pumping unit, without utilizing coil tubing. This reduced the overall cost of the well intervention by 60%, significantly reduced operational safety risks and is exceptionally suitable in the current challenging environment.\u0000 Similar to conventional cement packer, the operation begins with setting a plug inside the tubing below the targeted perforation depth and punching the tubing to create tubing-casing communication. The tubing was then flushed with surfactant and weak acid to remove any potential contaminants. The cement was then bullheaded from the surface through the tubing and into the casing while being chased by two foam wiper balls. The foam wiper balls were subsequently pushed with inhibited sea water mixed with cement retarder to prevent any leftover cement from hardening in the tubing. The hardened cement column in the production casing then acts as a barrier to satisfy operating guideline for two pressure barriers in a well.\u0000 Two cement packer jobs were performed during this campaign; one via conventional method with coil tubing unit (CTU) and a fit-for-purpose version without the CTU. Pressure test from the tubing and casing after the cement hardened indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool demonstrated thick column of good cement thus confirming the cement integrity of the non-CTU method. It was able to achieve similar pressure isolation as the conventional CTU method at 60% lower cost which allowed for significant cost saving. It also reduced the operation time by 50% since the cement was pumped at a higher rate through the well tubing. The turbulent flow regime via high rate pumping also resulted in thicker column of good cement (200m vs 120m) compared to conventional method. The only drawback encountered was the unexpected obstruction caused by leftover cement behind the foam ball. However, this can be removed through milling or fine-tuning the retarded sea water recipe. Post perforation, there was a sharp increase in the tubing pressure while the casing pressure remained low, further confirming the success of this method. This innovative method will be the standard method for any future cement packer operations while the conventional method with coil tubing will only be applied in complex situations.\u0000 This new Cement Packer technique has introduced substantial cost saving compared to the conventional cement packer method. It will enable monetization of more minor reservoirs. The method is exceptionally relevant to a mature field especially in the current challenging business environment.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77211326","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Practical Upscaling Process for Enhanced Water Alternating Gas : A Numerical Investigation","authors":"S. Majidaie, L. Hendraningrat, M. Hanifah","doi":"10.2118/205685-ms","DOIUrl":"https://doi.org/10.2118/205685-ms","url":null,"abstract":"\u0000 Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process.\u0000 Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated.\u0000 Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate.\u0000 Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78913905","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Algorithm-Assisted Platform Location Optmisation Using Mixed-Integer Programming for Cluster Development Strategy in the Gulf of Thailand","authors":"P. Ekkawong, Parichat Loboonlert, K. Seusutthiya, K. Wongpattananukul, Nuntanut Laoniyomthai, Jiraphas Thapchim, Rutchanok Nasomsong, Tepporn Satsue, Thanawat Charucharana, Kasidis Lhosupasirirat","doi":"10.2118/205765-ms","DOIUrl":"https://doi.org/10.2118/205765-ms","url":null,"abstract":"\u0000 The unique characteristic of gas fields in the Gulf of Thailand is the compartmentalized reservoir that requires a huge number of producing wells. The task of locating platform locations for whole field perspectives that also meet all operational criteria while minimizing the number of needed platforms is challenging. This decisional task has a critical impact on project viability, especially for marginal fields. This paper proposes an innovative solution to strengthen success in this business decision by integrating subsurface domain knowledge and optimization algorithms.\u0000 This study presents an optimization algorithm for determining the optimal locations of wellhead platforms with limited numbers to maximize hydrocarbon resources. Firstly, the algorithm performs verification matching between wellhead locations and subsurface targets throughout the field under drilling criteria. Next, the optimal platform locations are optimized using mixed-integer linear programming (MILP) with the primary objective of maximizing hydrocarbon resources. The algorithm literally runs with an increment in number of platforms until there is no incremental hydrocarbon resources gain and additionally summarizes the results as the number of platforms vs. coverage resources.\u0000 The algorithm has proven its viability by recommending more optimal platform locations in an actual field in the Gulf of Thailand. This algorithm-assisted workflow was able to reduce the number of required platforms. The main driver for this improved decision is that the MILP algorithm manage to improve well targeting and platform location selection under a large set of practical constraints. In contrast, manual workflow retains its limitations to consider them all.\u0000 This optimization also reduces the working time required for the whole process of well targeting and platform selection. Formerly, a typical workflow takes months of equivalent man-days. Conversely, this algorithm succeeded in completing the operation within just a few hours. Further, the subsurface team saved time by eliminating some repetitive tasks, i.e., they could focus on reviewing results extracted from the optimizer. Moreover, this work demonstrated the capability to extend and scaleup to other fields with similar concepts, which ultimately could lead to more benefits.\u0000 This innovative workflow translates the complicated subsurface procedure to a numerical optimization problem with a solid proven benefit from real field implementation. Apart from the positive business impact, this study shows that we can promote integration between modern data analytics and domain knowledge in oil and gas industry.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90630229","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}