Day 3 Wed, August 02, 2023最新文献

{"title":"Resolving Conflicting Recommendations in Investment Analysis","authors":"L. Akinpelu","doi":"10.2118/217160-ms","DOIUrl":"https://doi.org/10.2118/217160-ms","url":null,"abstract":"\u0000 Investment worth or investment performance metrics guide us in making investment decisions. These metrics address specific aspects of investments such as value creation, investment efficiency, risk exposure and risk mitigation amongst many considerations. With the complexity of most investment decisions and the size and scale of many investments especially in the Oil & Gas Industry, it is not enough to look at one dimension of investment. For instance, while most people will look favorably at value creation, which is the central premise of most investment decisions, in the context of limited capital, it is also relevant to factor into decision making, the cost of such value created. In other words, net present value (NPV) which is the time-tested value creation performance metric for investors, will not suffice for most current managerial considerations, particularly when comparing two or more investments. How much value is created is usually juxtaposed with the question: at what cost? In which case, analysts must, of necessity present to Management or the Project Decisions Board, NPV along with other performance metrics, usually the discounted profit to investment ratio, (DPI) and Rate of return (ROR). DPI is value creation per unit of investment or a measure of investment efficiency. The two measures complement each other and expand managerial insights as to the efficacy or otherwise of the investment(s) under consideration. In contemporary investment analysis, more emphasis is placed on investment efficiency reflecting investor preference for ever higher return on capital employed. If the two measures each recommend a particular investment over another, then the decision to invest is straight forward. The problem arises when one metric recommends one investment and the other metric recommends another - a situation that we describe as conflicting recommendations. Which investment to choose will require factoring into the investment decision several considerations beyond just value creation and investment efficiency. Considerations such as available capital, the company's short- and long-term business objectives, other potentially available opportunities all come into play.\u0000 This paper addresses issues arising from conflicting recommendations. We will highlight this problem by considering a simple example of two investments A and B of the same duration of five years and slightly different investment levels. We will limit our analysis to two popular investment metrics - Net present value (NPV) and discounted profit to investment ratio - DPI. The analysis presented is mainly deterministic and the investment opportunity space is limited to these two investments.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114643580","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":"An Improved Model for Accurate Description of Drilling Fluid Rheological Behaviour in Enhanced-Water and Low-Toxicity Oil-Based Muds","authors":"Folayan Adewale Johnson, A. Dosunmu, O. Boniface","doi":"10.2118/217171-ms","DOIUrl":"https://doi.org/10.2118/217171-ms","url":null,"abstract":"\u0000 In this study, a new rheological model was developed by the introduction of dimensionless plastic viscosity and shear rate correction factors (k and n) respectively to the plastic viscosity stress-term of the Bingham plastic rheological model with a view to correcting the under-estimation errors that are associated with the model at high shear rate condition in the pipe. Similarly, an effective yield stress τeff was also incorporated into the model to correctly describe the resistance to flow at low shear rate condition in the annulus by taking into account the effect of lowest shear rate stress on the yield-stress term of the model. The drilling fluid matrix consists of a low toxicity oil-based mud (LTOBM) and a high-performance, nanoparticle-enhanced water-based mud (EWBM). The rheological characteristics of these muds were evaluated at temperatures of 30°C, 60°C and 120°C and pressures of 14.7psi, 2500psi and 5000psi respectively. The experiments were conducted under API recommended standard equipment and procedures. Also, statistical tools were employed to quantify the degree of deviation of the model from experimental values.\u0000 Empirical results of the new model comparative rheological performance analysis with different existing models that are commonly used in the oil industries showed that the developed model accurately predicts fluid rheology better than the Bingham plastic model at both high and low shear rates conditions in the LTOBM and EWBM at all tested temperatures and pressures. The new model performed better than the Bingham plastic and the power law models at 30°C and 14.7psi for the EWBM with lowest standard error deviation of 1.5096 as against 4.4392 and 2.2573 for BPRM and PLRM respectively. Similarly, the average absolute error of the new model for EWBM at 30°C and 14.7psia is 1.6874 unlike BPRM and PLRM with (EAA) values of 5.3249 and 2.8704 respectively. The new model is not significantly temperature and pressure dependent at high shear rate.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124101000","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":"Thru Tubing Gaslift Installation Techniques in Dual Completion for Production Optimization and Improved Recovery in Brown Field Reservoirs","authors":"Toyin Arowosafe, Lucky Ishomo, A. Ogbebor, Esigie Benson, Rita Aigbefo","doi":"10.2118/217476-ms","DOIUrl":"https://doi.org/10.2118/217476-ms","url":null,"abstract":"\u0000 There are several non-rig well intervention methods used in the oil industry to resuscitate dead wells back to production. One of such methods implemented for non-gaslift wells (or previously gas lifted wells with shallow mandrel depths) is the installation of Thru Tubing Gas Lift (TTGL) equipment at a pre-determined depth on the walls of the tubing. Most TTGL assemblies are usually fitted with one orifice valve to provide single-point injection. As a result of the single-point injection, well performance might be impacted overtime as reservoir pressure depletes and produced fluid composition changes. In such cases, deepening of injection point is required to restore the wells to production and ensure maximum oil recovery. However, these TTGL installation techniques are especially delicate to implement in wells with dual completions due to the execution complexities introduce by the presence of the adjacent tubing string, existing or adjacent perforations and injection points in the tubing.\u0000 Dual oil producers, Wells X19B and Y22C were completed with dual completions without gas lift equipment in ED and ET field offshore Nigeria respectively. Well X19BL had TTGL installed about 8 years after it began production but, started to cycle gas through the TTGL point and was shut-in to curtail unwanted gas production to the surface facility. Well Y22CL and Wells Y22CU quit production on natural flow due to low well head pressure that resulted from decline in reservoir pressure\u0000 Rig based interventions was uneconomic owing to the fact the remaining reserves were marginal. This paper discusses the techniques, challenges and operational learnings from the first-time application of TTGL deepening and TTGL installation in both dual strings despite complexities from well architecture and previous TTGL installation","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131945178","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":"Microwave Assisted Technique for Oil Recovery from Oily Sludge Shale Drilled Cuttings","authors":"A. Agi, R. Junin, M. Shakuam, A. Gbadamosi, N. Ridzuan, S. Q. Mahat, J. Gbonhinbor, J. Oseh","doi":"10.2118/217140-ms","DOIUrl":"https://doi.org/10.2118/217140-ms","url":null,"abstract":"\u0000 Oily sludge, obtained during drilling processes, is considered a hazardous waste due to its composition. Conventional techniques of treating oily sludge indicates that desorption of the oily sludge is inhibited by asphaltenes. Herein, the effect of microwave power on oil recovery from contaminated drill cutting was investigated. Also, the effect of drilled cutting sizes on oil recovery was evaluated. Besides, the impact of microwave exposure time (10-60 minutes) on oil recovery was determined. Based on this, the mechanisms of microwave disintegration of the oily sludge were analyzed. Experimental result depicts that higher microwave power was more effective in the desorption of oil from the drilled cuttings. Moreover, more oil was recovered from smaller sizes of the drilled cuttings at a longer exposure time. The mechanisms of dipolar interaction and ionic conduction broke the hydrogen bond between the asphaltene and solid particles by this means enabling oil recovery of 59-99% from the contaminated drilled cuttings.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134299546","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":"Extending the Frontiers of Well Clean-Up Through Microemulsion Fluids-Based Technology Application","authors":"Felix O. Okoro, Bunmi Ayodele, Chidieber Anioke, E. Okolomma, Yahaya Ibrahim, Olufemi Mohammed, Catherine Mietei-Ileberi","doi":"10.2118/217207-ms","DOIUrl":"https://doi.org/10.2118/217207-ms","url":null,"abstract":"In oil & gas development projects, the target is to clean-up and put well onstream as quickly as possible. Apart from the economic benefits of early production, timely clean-up and well kick-off ensures that drill-in fluids and other materials used during drilling and completions do not create irreversible damage to the near wellbore region of the reservoir. In the FENE field there were 12 wells completed but not on production for over 20 years due to security and contractual challenges. These wells were drilled with water-based mud and left with filtered Seawater post completion. Given that the drill-in fluids, Seawater, and other materials were left in the wells for a long time, significant damage was suspected for the wells. These damage mechanisms include mud invasion, in-situ emulsion and water or emulsion blockage in the production interval. These identified damage mechanisms meant that the 12 wells require a dedicated clean-up with an optimal recipe to remove emulsion and other damages in the near wellbore. Conventional acid stimulation was initially proposed but was not endorsed due to suspected performance inefficiency and possible fluids-fluids incompatibility that could lead to further formation damage. After a comprehensive integrated review evaluating the potential damage mechanisms, a novel solution was identified which involves the use of a high-definition remediation fluid solution \"a Micro-emulsion Fluid (MEF) Based Technology\" to remove identified near wellbore damage. Prior to field execution, a rigorous laboratory test was performed with fluid samples from the wells and the result indicated good near-wellbore damage removal, reservoir fluids and Seawater compatibility. The MEF based technology has so far been successfully deployed in 9 wells (with the remaining 3 wells in plan) and has effectively removed suspected near wellbore and formation damage. The wells are currently on production with a 33% increase in performance above plan. This technical paper explains the process of candidate treatment selection, solution design, job execution, and production gains from deploying MEF based solution on these 9 wells executed till date.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133728123","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":"Gas Well Deliquification Assessment and Nag-To-AG Compression Opportunity – Resolving Liquid Loading Issues in Gas Cap Blow Down Development and Salvaging Value via Second Stage Compression","authors":"Basil Ogbunude, Uchenna Udobata, Eelah Muzan, Sunday Maxwell-Amgbaduba, O. Okereke, Olanrewaju Alaka, C. Barka, M. Nanpan, A. Laoye","doi":"10.2118/217159-ms","DOIUrl":"https://doi.org/10.2118/217159-ms","url":null,"abstract":"\u0000 A hallmark of the optimal development of hydrocarbon fields is sustenance of production plateau over the life of the wells. This becomes challenging as wells approach terminal production stages due to high water production, reservoir pressure decline, high gas or condensate production, etc. These issues are relatively easier to resolve for oil wells with typical WRFM activities such as water shut offs and reperforations. WRFM activities for gas wells at late life production are more challenging and typically involves resolution of liquid loading issues and reservoir pressure decline.\u0000 Gas reservoirs typically experience significant reservoir pressure decline over time (up to 75% observed in the study field) in the absence of an energy recharge system. Water-drive gas reservoirs benefit from sustained reservoir pressure, but they are more susceptible to early water breakthrough which negatively impacts overall recovery. In most cases, the combination of liquid loading and reservoir pressure decline negatively impact the wells, leading to a more complex production challenge requiring detailed assessments and solutions. The liquid loading effects in gas wells reduces the overall recoverable volumes due to early liquid breakthrough which leaves some bypassed gas behind. In many cases, the liquid loaded wells become more difficult to lift as the wellhead pressures drop below the facility inlet pressures, rendering the impacted wells unable to flow.\u0000 Komu field has been in production for over 20 years, with >3.5Tscf of gas already recovered from a gas-cap blow down project, including 7 years of compression. Gas production decline and liquid loading necessitated a full well Deliquification study to assess the performance improvement options for these late-life gas wells. This includes velocity strings, foam lifts, gas lift, pumping, water shut-off, intermittent production & compression, with the ultimate aim of achieving reduced tubing head pressure and/or critical rate and increasing well capacity. The assessment and selection of optimal solutions were based on reservoir & well parameters and ease of execution. Subsurface modeling indicated second stage compression, via a lower inlet-pressure nodal compressor or wellhead compressors, presented the best option for additional gas recovery, though at potentially prohibitive costs. Further inventory review presented the opportunity to revamp two existing Associated Gas (AG) compressors in Komu field and convert them to NAG compressors, significantly reducing the cost implications of the option. This paper details the integrated evaluation carried out to select the optimal solutions in the development of an AG-to-NAG solution in Komu field and prescribes the opportunity realization strategy for maximum value addition to the asset.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133408390","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":"Drilling into a Charge Shadow Zone of a Prolific Niger Delta Field: Learnings from Well-X","authors":"Ogunlana Ayodeji, Akingbade Kolawole, Falade Oladipo, Obilaja Olusegun, Chima Chikezie, H. Farran, Jenakumo Timipere, Orakwue Anita","doi":"10.2118/217127-ms","DOIUrl":"https://doi.org/10.2118/217127-ms","url":null,"abstract":"\u0000 Three decades on, a brownfield still springs surprises in the Deepwater Niger Delta. An Exploration well, Well-X was recently drilled targeting an amplitude-supported opportunity within a prolific geological interval in a Deepwater field. The well discovered excellent reservoir of 78 feet thick sand with 100% net-to-gross and 32% porosity, but turned out wet, with no evidence of hydrocarbon. The post well evaluation indicate that the excellent reservoir properties contributed to the false-positive amplitude anomaly that is typically attributed to a direct-hydrocarbon indicator in prospective reservoirs.\u0000 A post-mortem was conducted to understand which element of the petroleum system failed resulting in the wet well outcome. Access to hydrocarbon charge and trap integrity were re-assessed as two possible geological failure mechanisms. Results of the investigation and preponderance of available evidence indicated that lack of charge access was the most likely reason for failure as there was no trace of thermogenic hydrocarbons in the entire stratigraphic interval drilled. The post-mortem also revealed that deep-seated faults extending into the charge kitchen act as major hydrocarbon migration conduits into target reservoirs within the field. Unfortunately, Well-X target reservoir was not connected to any of such faults and is located in what is now considered a ‘Charge-shadow’ zone of the field. A Fluid Inclusion Study (FIS) required to validate the charge theory is currently being embarked upon.\u0000 A key learning from this well outcome is that access to charge is not ubiquitous, even in prolific fields or basins. A good understanding and clear definition of plausible migration pathways are critical to exploration success.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132514873","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":"Polymeric Gel Treatment for Water Shutoff – A Case Study","authors":"A. Author, S. Author, O. K. Author, O. O. Author","doi":"10.2118/217110-ms","DOIUrl":"https://doi.org/10.2118/217110-ms","url":null,"abstract":"\u0000 Production from several matured oil and gas fields is impacted by high water cut. Common causes of excess water production in wells are coning, inflow through fractures and poor cement quality behind casing. Operators always aim at increasing the recovery of oil and gas and prolong well life in the absence of or negligible water cut. Polymeric gel system is a clear fluid formulated with low-molecular-weight polymer which allows penetration into matrix pore spaces for complete shut-off. Its low viscosity prior to crosslinking aids its injectivity; after placement in small openings such as pore throats and channels in cement behind casing, the final product is a rubber-like ring gel which penetrates formation matrix to reduce permeability and eventual shut-off flow. This paper focuses on the application of polymeric gel solution designed to shut off water production in two wells in Niger Delta. The candidate wells were carefully selected following a comprehensive review of the well schematic, petrophysical information and the reservoir performance monitoring logs. Based on the results of the data analyzed, polymer gel system was recommended. The required laboratory tests were conducted to confirm gelation time prior to field deployment. Coiled tubing and thru tubing inflatable packer were the preferred deployment method for precise treatment placement. The wells were shut-in for five days and surface samples were collected and kept in the water bath under downhole temperature conditions to allow curing of the treatment. The wells were opened after the curing time, and pressure tested against cured treatment system downhole and held for 10mins. The positive results from the pressure tests in both wells showed that total shut-off of the existing perforations were successful. The wells were thereafter re-perforated at shallower depths and production sustained on both wells.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116271993","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":"Integration of Technologies for Heavy Oil Production – An NNPC E&P Ltd Approach","authors":"E. Ifeduba, H. Ijomanta, S. M. Hamza, O. Ayeni, N. A. Udo, A. S. Niyang, O. Okoh, Y. Akinnurun, M. Ogweda, T. Emetoh, J. O. Esene, B. Ojeaga","doi":"10.2118/217194-ms","DOIUrl":"https://doi.org/10.2118/217194-ms","url":null,"abstract":"\u0000 NNPC E&P Ltd (NEPL) recently successfully drilled, completed and tested the Abura 6ST well which integrated multiple Improved Oil Recovery techniques to develop some heavy oil reservoirs in the Abura field. The 1AB6 and 2AB6 reservoir fluids have viscosities of 10 and 17 Centipoise and API gravity ranging from 16 – 20API° which is a marked variation from NEPL's conventional resources. NEPL is estimated to have over 1.2B barrels of heavy crude oil in her portfolio therefore an attempt to unlock the potential from these reservoirs had a lot of implication for the company. Conventional methods of producing this reservoir were not economically viable mainly due to the high oil viscosity and consequent preferential flow of water rather than oil.\u0000 The NEPL team resorted to integration of multiple improved oil recovery IOR techniques to ensure an economically viable well.The first of such improved oil recovery techniques was the use the ESP as the Abura field did not have any gas source for gas lift. Artificial lift was to eliminate flow assurance issues that such a hydrocarbon system would have. Another IOR technique was the combination of horizontal and deviated well bores to drain the reservoirs through a single wellbore in a commingled fashion. The well cuts across the shallowest reservoir as a high angle section and lands in the deeper reservoir as a horizontal well. To ensure preferential flow of oil from the reservoir into the wellbore, Autonomous Inflow Control Device AICD was deployed for both the horizontal and vertical sections of the completion which uses viscosity differences to prevent early water breakthrough and reduce water production.\u0000 To meet NUPRC's back allocation requirements, hydrocarbon fluid samples were collected during the drilling operation and unique fingerprint markers were identified which will aid in the determination of each reservoir's production contribution for proper hydrocarbon accounting. In the completions aspect of the design, Swell packers for zonal segmentation, Micro-emulsion breaker system for near well-bore remediation and improved permeability, downhole gauges & sensors and a Y-Tool assembly for alternate access in rigless intervention mode. The Abura 6ST well produced circa 2900 BOPD on choke 28/64 and ESP frequency of 40Hz.This paper seeks to elucidate on some of the IOR technologies and how they were integrated to facilitate the delivery of the first heavy oil ESP well in NEPL's direct operations.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128258247","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 Hydrocarbon Allocation – A Machine Learning Approach","authors":"K. I. Diaso, J. Kalio, S. Owoseni, E. Duruzor, B. Onasanya","doi":"10.2118/217225-ms","DOIUrl":"https://doi.org/10.2118/217225-ms","url":null,"abstract":"\u0000 The current conventional method of hydrocarbon production allocation of reservoir fluids’ contribution to the separate producing strings from commingled production in the oil and gas industry considers some rigid assumptions that make the allocated volume mostly unreasonable. This uncertainty is usually due to the fixed decline rate assumption normally adopted for a specified period until a new well test of the contributing strings is available to generate a new allocation factor anytime production allocation is required.\u0000 This paper presents an artificial intelligence approach in the determination of real-time allocation factors for determining contributing production flow performance from commingled production using a machine learning algorithm with the fixed rate assumption using well flow parameters such as the flowing tubing head pressure, flowline pressure and other well parameters to generate transient rates for the producing strings, to create new allocation factor when required.\u0000 Data from marginal fields in the Niger Delta were used as case studies and the results generated from this exercise after proper data pre-processing depict reasonable output with precision of high confidence level. Results from this approach can also be used in the absence of a reliable well test.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"101 4 Pt 1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128403113","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}