Day 3 Wed, August 02, 2023最新文献

{"title":"Achieving Sustainable Energy Transition; - What Works in Sub-Saharan Africa","authors":"F. M. Kelechi, I. S. Ogbodo, J. A. Adah, A. A. Aribisala, P. Akagbosu","doi":"10.2118/217226-ms","DOIUrl":"https://doi.org/10.2118/217226-ms","url":null,"abstract":"\u0000 According to a United Nations report from November, 2022, the world population reached 8 billion for the first time in human history with 6.74 billion people living in low and middle - income countries (LMICs) and 1.3 billion living in developed countries. 53 of Africa's 54 countries fall under the former category. The population of Africa is estimated to be 1.4 billion with 1.17 billion in sub-Saharan Africa. Presently, 770 million people globally have no access to electricity mostly in Africa and Asia with 3.8 billion depending on solid fuels for cooking and other domestic uses. Data obtained from WHO reported that 568 million people in sub-Saharan Africa are living without access to electricity and clean energy. In developing nations, wood, charcoal, and dung are commonly used as traditional cooking fuels, with wood being the primary source of energy. The emission from these fuels in addition to those from fossil fuels further reduces the quality of air which causes ambient air pollution, a condition with adverse effects on human health. However, there are initiatives that have been adopted to alleviate the problems including the future expectation for global access to clean energy as conveyed in the 2030 United Nations Sustainable Development Goals (goal number 7); the 2063 African Union Commission Agenda; the Paris Agreement at COP21; and the United Nations Sustainable Energy for All (SE4A). This paper reviews historical trends in energy usage in sub-Saharan Africa, the present conditions and status of development, across policy and technological prongs, in terms of the current energy transition. Furthermore, the paper seeks to highlight opportunities for future sustainable energy development across all sectors and businesses in order to provide energy to the 568 million without access in sub-Saharan Africa, while bearing in mind the environmental implications for the global population at large.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"22 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":"127167266","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":"Panacea to Domestic Gas Supply Accessibility and Affordability in Nigeria","authors":"J. Ugolo, M. Iwegbu","doi":"10.2118/217157-ms","DOIUrl":"https://doi.org/10.2118/217157-ms","url":null,"abstract":"\u0000 Nigeria with a proven gas resource base of over 206tcf possesses the biggest gas reserve in the continent of Africa and is the 9th largest in the World (NUPRC website, 2021). However, Nigeria faces the challenge of making clean cooking gas accessible and affordable for its populace. Investments in making cooking gas affordable will improve the economy of the average household and reduced carbon footprint in this part of the world.\u0000 The Nigerian Government by March 29th, 2021 proclaimed the following decade, the decade of gas reform and development. The blueprint of a Nigerian Gas Master Plan (NGMP) focusing on accelerating the growth of the country's gas sector was to be adopted. Efforts required in this plan would include developing better-adapted technologies and delivery models, and stronger institutional frameworks. Substantial efforts are required across the region to help convert the abundant natural gas resources into adequate domestic gas utilization and hence for national development.\u0000 A key factor for making clean gas accessible and affordable for all, is to have in place, gas infrastructure for storage and distribution. A number of Nigerian oil and gas production platforms still flare their gas due to inadequate gas processing, treatment, and storage facilities. Other factors hindering development of the domestic gas sector include the non-adoption of modern gas recovery technology, inadequate media enlightenment, and stakeholders’ willingness to invest in carbon footprint reduction initiatives.\u0000 Using quantitative research methodology, the researcher looked at the pricing of Liquified Petroleum Gas (LPG) over a 7-year (2016-2022) period. Examination of the gas infrastructure development within the same period was also analysed to determine if more gas has been made available in the Nigerian market. A survey was done to ascertain possible factors affecting investment in gas sector of Nigeria. Secondary data was obtained from the World bank databases showing revenue generated from gas amongst top 10 African countries. This helped to show value obtained from the gas sector.\u0000 Key benefits for making domestic gas accessible and affordable would include, improved Gross Value Addition (GVA) for investors and the national economy, better health conditions for the millions already affected by using solid biomass (firewood and charcoal) for cooking as well as reduction in carbon emissions.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"14 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":"127200894","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":"Field Surface Planner Algorithm for Integrated Gas Asset Management","authors":"Y. Adeeyo, A. Abu, G. O. Adun, M. Lucciano-Gabriel","doi":"10.2118/217183-ms","DOIUrl":"https://doi.org/10.2118/217183-ms","url":null,"abstract":"\u0000 As the world transitions towards a more sustainable energy landscape, the need for a less environmentally harmful transition fuel becomes increasingly crucial. This has led to renewed interest in developing previously abandoned natural gas fields. In this paper, we present Field Surface Planner Algorithm (FSPA), a DCA-based model implemented in Python, which aims to generate an effective investment timing strategy for bringing new wells online in large gas fields. The model considers various surface facilities and commercial constraints, while prioritizing the fulfillment of contractual gas demand.\u0000 FSPA's algorithm revolves around a sales error concept, which quantifies the disparity between the current sales gas rate and the nominated gas demand. By comparing this sales error against a predetermined error tolerance, the model determines the optimal timing for introducing new wells into production. This approach ensures that the gas field's total sales gas rate remains in line with the nominated gas demand, while minimizing any potential environmental impact.\u0000 To ensure efficient operation, FSPA operates within the bounds of nominated gas demand constraints and facility constraints. Nominated gas demand constraints serve as a limit against which the on-stream dates and DCA forecasts for future wells are optimized, minimizing the need for flaring gas. Facility constraints restrict the volume of gas supply that the algorithm optimizes, aligning it with the capabilities of the surface facilities.\u0000 During a well's initial contribution, FSPA generates accurate DCA forecasts based on several key factors, including the exact amount of sales gas required to close existing gaps, the well's reserves, and economic limitations. This information aids in making informed decisions regarding short-term production shortfalls and facilitates effective negotiation with customers, ultimately delivering substantial value for the organization involved in gas field development.\u0000 By providing an efficient solution for well sequencing, the proposed model significantly reduces gas flaring costs, minimizes opportunity costs associated with production shortfalls, and assists in short-term decision-making processes. Overall, it offers a valuable contribution to sustainable energy transition efforts and promotes responsible development in the gas industry.","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":"125426366","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":"Eliminating Associated Gas Flares in The Nigerian Stranded Marginal Field Oil Fields: The Otakikpo Field Strategy","authors":"J. Akinyemi, Tamunotroko kala-otaji","doi":"10.2118/217128-ms","DOIUrl":"https://doi.org/10.2118/217128-ms","url":null,"abstract":"\u0000 The Otakikpo marginal field was carved out of OML 11 and is situated in the southern part of the license. The field was discovered with Otakikpo-02 in 1983 and was further appraised with Otakikpo-03 in 1986. The wells encountered hydrocarbons in 4 stacked oil and gas bearing sands (C5000, C6000, C7000 and E1000). The field is operated by Green Energy International Limited (GEIL).\u0000 The field currently produces ~10,500 bopd with significant associated gas (AG) production from the wells with average GOR of ~1000 scf/bbl. Compositional analysis shows that the associated gas is rich in C3 – C4 components (~ 8%) and C5 – C7 (~ 3%) making it ideal for NGLs (LPG and condensates) extractions.\u0000 Most natural gas utilization projects require securing constant gas production contracts for between 10-20 years and for constant rates > 50 MMSCFD. However, the Otakikpo field, the associated gas reserves do not meet this threshold and the production profiles are at best unpredictable.\u0000 To address these issues, an innovative strategy is required to accelerate reduction in the field's AG flaring. A qualitative and quantitative screening of the various gas utilization concepts against some critical decision drivers (AG production profile, scalability, CAPEX) led to the recommendation of a modular LPG extraction plant for the heavier components of the AG and Gas to Power for the lean gas.\u0000 The conventional approach of piping gas from a remote field needs to be replaced with a less orthodox technique of \"bringing the plant to the gas\". This eliminates the need for expensive pipeline and compression since the facility is within the Otakikpo field flow station. Furthermore, a modular scalable strategy with small footprint plant that is quick to deploy and easy to relocate was recommended as the best solution for the field.\u0000 The Operator successfully commissioned the 12MMSCFD modular LPG extraction plant and 6MW power generating plants. This scale of modular LPG plant will be the first to be installed in the country. This strategy could be adopted by other small fields in addressing AG flares caused by stranded pockets of gas located in oil fields in the Niger Delta thus supporting the Government's aspiration of eliminating AG flares.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"35 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":"127524615","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":"Improving the Flowability of Waxy Crude Oil Using Orange Seed Oil Derived Additive","authors":"A. Fadairo, G. Adeyemi, S. Egenhoff, Stephen Obia, Opeyemi Oni, A. Oladepo, Richmond Nwaoke","doi":"10.2118/217254-ms","DOIUrl":"https://doi.org/10.2118/217254-ms","url":null,"abstract":"\u0000 The field development of deep offshore and onshore platforms has proven to be extremely expensive hence the necessity of painstaking decision making while checking for the feasibility of various field development plans. The guarantee of waxy crude oil production has proven to be a major problem during the pipeline transport of produced hydrocarbon from the production platforms to the storage plants. Billions of dollars are spent to control the deposition of paraffin in pipe network. The major factor causing wax deposition includes temperature, pour point of the crude oil sample and most importantly the paraffin content of the crude oil sample amongst other factors. It has been proven over the years that the chemical method of controlling wax deposition is the most efficient for wax deposition control as it tackles the root cause of the wax formation and restricts it. However, as efficient as the chemical methods, a great number of chemists mostly utilize certain conventional chemicals rather than others which include Triethanolamine (TEA) and xylene which have proven to be highly priced and usually not environmentally friendly. Various research has been carried out in the hunt for other substitute chemicals for the control of wax formation. Reports have shown that the use of seed oil has been the leading research in wax formation control and deposition. In this study, the seed oils generated from orange seed were converted to biodiesels by a process termed transesterification as there is a significant need to reduce the seed oil viscosity because lower viscous phase greatly improve flow when mix with the waxy crude oil. The study demonstrated that biodiesel made from orange seed oil has the ability to slow wax formation and deposition by lowering the cloud point and pour point in the waxy hydrocarbon.","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":"127626454","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 Applications of a New Sand Screen Technology to Mitigate Water Injection Challenges, A Case Study for X Field, Nigeria","authors":"J. Ngerebara, O. Alawode, I. Hamzat, Ross Wilson, James Anderson, M. Moradi, E. Emifoniye, I. Ugbor, N. Okonkwo","doi":"10.2118/217201-ms","DOIUrl":"https://doi.org/10.2118/217201-ms","url":null,"abstract":"\u0000 A number of techniques have been applied to improve the integrity and therefore long-term performance of injection wells to eventually enhance oil recovery in one of the fields in Nigeria.\u0000 Comprehensive data analysis suggested formation solids due to the phenomena of water hammer, backflow and crossflow are major integrity problems in several injection wells in the targeted field, especially with fines migration and accumulation inside the lower completion during sudden or prolonged well shut-in. Formation solids are normally resident in the reservoir during the steady injection but can be mobilized into the wellbore during sudden shut-ins due to powerful transient flow effects such as water Hammer, cross flow and backflow. This would result in high bottom hole injection pressure (BHIP), diminished or loss of injectivity, screen plugging and erosion of downhole equipment which may lead to the inability to maintain pressure support to pair producer. Therefore, an intervention, remediation, side-track or loss of wellbore may be deemed inevitable. Application of other technologies has proven unsuccessful in these wells for various reasons.\u0000 A new sand control technology specifically developed for such projects was chosen as the best option among all available alternatives based on a matrix of requirements for the new campaign. This technology which would be installed on the closest point to the sandface was chosen as it isolates the reservoir from wellbore during well shut in, constitute no obstruction to Intervention tools, provides full access to the lower completion sand face during injection and/or intervention without restriction or pressure drop, withstands well conditions for the entire well life, is compatible with SAS, GP completions and direct wrap or metal mesh screens and it is a low CAPEX solution compared to other alternatives.\u0000 Rigorous compatibility tests and practices including modelling, backflow, cross flow, erosion and plugging tests were performed to ensure that well completions and operations requirements were met for field X. The results from all studies were positive and successful and therefore the technology was approved to be installed in the wells.\u0000 The NRV technology has already been installed in 3 wells to date. In this paper, the pre-qualification studies, the full qualification test results and post-installation well performance would be discussed. Also, the lesson learnt from these installations will be shared.\u0000 The wells’ performance data shows that this completion technology has successfully delivered the target rate and desired performance so far and provided the field X team with a robust solution to mitigate the common issues with the injection wells while avoiding costly interventions.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"24 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":"132123050","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":"Mega Project with High Shaping Complexity During Front End Loading: A Niger Delta Case Study","authors":"Peter Obidike, Elisha Ezekiel-Hart, Akinwumi Oluwafemi","doi":"10.2118/217126-ms","DOIUrl":"https://doi.org/10.2118/217126-ms","url":null,"abstract":"\u0000 The three dimensions of complexity of Mega projects according to Edward and Nandurdikar are about Scope, Organizational and Shaping. According to Edward and Nandurdikar in \"Leading Complex Projects\", there are instances where a Mega project with a regular scope can result to extra-ordinary scope and organizational complexity. The experience we intend to share in this paper demonstrates that a project with a simple scope can have a complex shaping process. In projects maturation, the shaping process is where the value is created, while in the execution and operation phases we realize the value. In the Niger Delta case study that we share in this paper, a simple upstream project that initially required drilling of 5 non-associated gas (NAG) wells (in a first phase of development), flowlines, and hookup to a manifold 100 meters away from the wells, manifested high shaping complexity. This was due to different reasons stemming from involvement of large number of stakeholders (internal and external), technical (subsurface and surface) and non-technical risks including commercials. This paper will discuss the early wins in the subsurface development strategy, changes in regulatory environment from introduction of Petroleum Industry Act (PIA). The PIA impacts on regulator availability, required different interfaces for upstream and downstream and risks to resource ownership within the projects contract period and the impact on the shaping process are discussed. The objective is to share these learnings on the key shaping issues and perspectives on things that could have been done differently for a more desirable shaping outcome. Some of these issues include subsurface uncertainties, risks, and the robustness of the development strategy to support the gas supply obligation, the phased development and confidence of external stakeholders to the operators planned development strategy and commercial aspects of a required update to the gas supply agreement.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"85 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":"122948322","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 Sustainable Pathway to Achieving Operational Efficiency While Reducing Carbon Emissions Using Remote Operations and Drilling Automation","authors":"Loretta Umeonaku, Ben Aluu, Kenechi Okafor, John Atakpa","doi":"10.2118/217134-ms","DOIUrl":"https://doi.org/10.2118/217134-ms","url":null,"abstract":"\u0000 In recent times, remote operations in drilling and wellsite activities have evolved from a nice-to-have service to a vital solution for delivering world-class logging and well placement management in the oil and gas industry. The drive towards remote operations accelerated during the Covid-19 pandemic where it was beneficial to operate with minimal personnel in order to limit their exposure. Moreso, with 2050 being about three decades from now, energy companies are strengthening their commitments to achieving net zero global carbon emissions in solidarity with the Paris agreement of 2015 geared at reducing the impact of climate change. It is safe to say that remote operations services are poised to change the future of oil and gas operations as more operators jump on board and see the true benefit of remote operations from a safety, cost-saving, and carbon footprint reduction viewpoint.\u0000 In May 2020, as part of Baker Hughes Drilling Services Nigeria's strategy for carbon reduction and carving a road map to automated drilling, the first Remote Operations centre in Sub-Saharan Africa was launched. Equipped with robust high-speed data links to connect to multiple rig sites enabling 24/7 monitoring and control of multiple drilling operations. The centre provides real time unified data streaming and visualisation enabling enhanced well monitoring and management. In addition, it is manned by highly experienced drilling professionals who collaborate with various subject matter experts to optimise overall service delivery.\u0000 This paper demonstrates the significant value of adopting remote operations in delivering optimized drilling and logging services. Two case studies illustrating the approach and strategies utilised in safely and flawlessly delivering two wells remotely will be elucidated. The technicalities deployed to save one of the operators from shutting down in the middle of the Covid-19 pandemic, the re-manning model utilized, and workflow schematics will be discussed. Finally, it quantifies the amount of carbon footprint reduction achieved, lessons learnt, and optimization opportunities.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"141 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":"124515622","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":"Prediction of Thermal Conductivity of Rocks in Geothermal Field Using Machine Learning Methods: a Comparative Approach","authors":"P. Ekeopara, C. Nwosu, F. M. Kelechi, C. Nwadiaro, K. K. ThankGod","doi":"10.2118/217217-ms","DOIUrl":"https://doi.org/10.2118/217217-ms","url":null,"abstract":"\u0000 Thermal conductivity of rocks defined as the ability of rocks to transmit heat, can indicate the potential for geothermal resource in a given location. While direct laboratory core sample analysis and indirect analysis leveraging empirical correlations from electric logs are used to determine thermal conductivity of rocks, they are usually expensive, time consuming and difficult to implement. Hence, in this study, several machine learning methods specifically Gradient Boosting Regressor, Random Forest, K-nearest neighbour, ensemble method (voting regressor), and Artificial Neural Networks were developed for the real-time prediction of thermal conductivity of rocks in geothermal wells. Data being obtained from Utah Forge field project included drilling data, thermal conductivity data and other necessary information from the field. With real-time sensor drilling data such as Rate of penetration (ROP), surface RPM, Flow in, Weight on bit (WOB), and Pump pressure, as input parameters and matrix thermal conductivity (MTC) as output, the models were developed. The results obtained from this study, showed excellent performances for majority of the models. However, it was observed that the ensemble voting regressor, which combined the top three models was able to predict thermal conductivity with above 89% and 80% R2 scores on the train and validation datasets respectively. Thus, this research work describes the feasibility of leveraging several machine learning methods in estimating thermal conductivity of rocks which is cost effective, and practically achievable.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"9 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":"127621719","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":"Uncertainty Management for Well Planning and Execution; Case Study of New Drills in Tom Boy Field in the Swamp Niger Delta","authors":"B. Taiwo, T. Z. Igiri, J. Onyeji, Oduware Ohenhen, Fagbowore Olufisayo, F. Zen, Asaolu Ayodele, Oragwu Aluba, Chukwuka Clement","doi":"10.2118/217193-ms","DOIUrl":"https://doi.org/10.2118/217193-ms","url":null,"abstract":"\u0000 The Tom Boy field is one of the oldest fields in the Niger Delta Basin with more than 30 wells at the time of initiating infill development drilling campaign. The drilling campaign of 11 wells (10 producers and 1 Water Source) was planned to develop reservoirs that have not been produced and to optimize production from developed reservoirs. Numerous challenges were faced in the planning and execution phases for the infill drilling. Key uncertainties include, Structure, Stratigraphy, wellbore placement issues, current fluid saturation/contacts in the reservoirs, and wellbore instability issues as wells drilled through pressure-depleted reservoirs. Thus, this paper addressed how these uncertainties were managed during planning and execution of the drilling program.\u0000 Through integration of detailed Uncertainty Management Plan (UMP) during execution, the team eliminated the need for drilling pilot well in an instance; and in another scenario, successfully landed a horizontal well in a 10ft thick sand. The methodology used include deployment of improved technologies, proper planning, appropriate mud-weight design, history matched reservoir models, optimizing subsurface target locations for data acquisition and proper well sequencing on the drilling schedule was used to understand the current saturation in some target reservoirs and target the sweet spot in the reservoir. Pre-execution decision tree assisted with making quick real time decisions while drilling the landing and lateral hole sections based on the outcome of each uncertainty identified in the UMP signpost. Decision tree incorporated all information (earth model, seismic data, dips, local pre-drill model etc.) integrated with potential outcomes from real-time reservoir navigation data obtained from geosteering tools to aid well placement in an optimal position within clean sand. All wells were successfully drilled and completed in the sweet spot of target reservoirs to meet pre-drill production targets.","PeriodicalId":407977,"journal":{"name":"Day 3 Wed, August 02, 2023","volume":"6 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":"114772653","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}