With the increasing of water injection activities especially for marginal or stranded fields, the well pair analysis in routine water injection surveillance is crucial to understand the reservoir performance and identify opportunities to improve the ultimate oil recovery. This article aims to propose an alternative technique to evaluate the communication strength between injector – producer well pairs based on statistical and machine learning algorithms. The proposed technique is applied to an offshore water injection field located in the North Sea from open-source data. A novel formulation to quantify the communication strength coefficient for an injector – producer well pair was derived from the Spearman's rank correlation coefficient. The calculation is controlled with injection/production rates pattern for each well pair. Subsequently, multivariate parametric regression is performed to model the communication strength coefficient as a function of injector – producer spacing, injection pattern (dip angle), and reservoir permeability-thickness. Monte Carlo technique is then applied to simulate 100 cases prepared using the uniform probability distribution. Afterward, the communication strength for all the well pairs in the field is classified based on K-means clustering. To identify opportunities to improve the effectiveness of water injection operation, random forest and support vector machine algorithms are used to evaluate the effect of the reservoir and operational parameters on the communication strength of the injector – producer well pair. It is identified that the communication strength for all the well pairs in the field varying from limited, intermediate, and good communication. Good communication strength shows the correlation coefficient of more than 0.50 which indicates there is a good correlation between injection and production rates pattern. It is also observed that reservoir permeability-thickness is the most variable importance that affects the communication strength between injector and producer well pair. It is followed by the injector-producer spacing and reservoir dip angle. The optimum condition has been identified to formulate the screening criteria in order to obtain the good communication strength between injector and producer well pair. This result help in identifying the producer with limited communication strength with the existing injector and low production rate to be converted as the injector well. Unlike reservoir simulation which is a very expensive and time-consuming process, this work provides a quick and inexpensive alternative to evaluate the communication strength of injector-producer well pair from widely available measurements of production and injection rates at existing wells. Application of this novel workflow provides insight for better decision-making and can be a prudent complementary tool to quantify the effectiveness of the water injection operation and identify opportunities.
{"title":"Well Pair Based Communication Strength Analysis for Water Injection Reservoir Surveillance Using Monte Carlo Simulation Coupled with Machine Learning Approach","authors":"Edo Pratama, S. Ridha, B. M. Negash","doi":"10.4043/31438-ms","DOIUrl":"https://doi.org/10.4043/31438-ms","url":null,"abstract":"\u0000 With the increasing of water injection activities especially for marginal or stranded fields, the well pair analysis in routine water injection surveillance is crucial to understand the reservoir performance and identify opportunities to improve the ultimate oil recovery. This article aims to propose an alternative technique to evaluate the communication strength between injector – producer well pairs based on statistical and machine learning algorithms. The proposed technique is applied to an offshore water injection field located in the North Sea from open-source data.\u0000 A novel formulation to quantify the communication strength coefficient for an injector – producer well pair was derived from the Spearman's rank correlation coefficient. The calculation is controlled with injection/production rates pattern for each well pair. Subsequently, multivariate parametric regression is performed to model the communication strength coefficient as a function of injector – producer spacing, injection pattern (dip angle), and reservoir permeability-thickness. Monte Carlo technique is then applied to simulate 100 cases prepared using the uniform probability distribution. Afterward, the communication strength for all the well pairs in the field is classified based on K-means clustering. To identify opportunities to improve the effectiveness of water injection operation, random forest and support vector machine algorithms are used to evaluate the effect of the reservoir and operational parameters on the communication strength of the injector – producer well pair.\u0000 It is identified that the communication strength for all the well pairs in the field varying from limited, intermediate, and good communication. Good communication strength shows the correlation coefficient of more than 0.50 which indicates there is a good correlation between injection and production rates pattern. It is also observed that reservoir permeability-thickness is the most variable importance that affects the communication strength between injector and producer well pair. It is followed by the injector-producer spacing and reservoir dip angle. The optimum condition has been identified to formulate the screening criteria in order to obtain the good communication strength between injector and producer well pair. This result help in identifying the producer with limited communication strength with the existing injector and low production rate to be converted as the injector well.\u0000 Unlike reservoir simulation which is a very expensive and time-consuming process, this work provides a quick and inexpensive alternative to evaluate the communication strength of injector-producer well pair from widely available measurements of production and injection rates at existing wells. Application of this novel workflow provides insight for better decision-making and can be a prudent complementary tool to quantify the effectiveness of the water injection operation and identify opportunities.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84240466","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}
Deterioration of carbon steel water injection subsea pipelines caused by internal corrosion is a common problem in oil fields around the world. Addressing this issue requires costly and complex water management solutions or could lead to reduced performance and total replacement of corroded pipelines. This paper shall present the Polymer Lined Pipe (PLP) technology, a field proven solution to the water injection corrosion challenges, extensively used in the North Sea. A description of the key building blocks and the recent technology qualifications shall highlight the latest product development. Eventually, the main fabrication and installation steps shall be presented in view of a regional PLP application. A regional business case comparing the three water injection corrosion approaches shall highlight the typical economic metrics that could be achieved thanks to the use of PLP technology. Today, this technology is accessible to operators in the Asia Pacific region with the recent opening of the Bintan Spoolbase in Indonesia enabling the deployment polymer lined water injection pipelines using the reel-lay method of installation. The strategic location of the spoolbase eliminates the significant intercontinental transit costs and the reel-lay method reduces offshore vessel days normally associated with conventional pipe-lay methods (S-lay and J-lay).
{"title":"Polymer Lining – A Solution for Water Injection Corrosion Challenges in Asia","authors":"Radzlan Ahmad Suhaimi, Allan Feeney, Arnaud Roux","doi":"10.4043/31474-ms","DOIUrl":"https://doi.org/10.4043/31474-ms","url":null,"abstract":"\u0000 Deterioration of carbon steel water injection subsea pipelines caused by internal corrosion is a common problem in oil fields around the world. Addressing this issue requires costly and complex water management solutions or could lead to reduced performance and total replacement of corroded pipelines.\u0000 This paper shall present the Polymer Lined Pipe (PLP) technology, a field proven solution to the water injection corrosion challenges, extensively used in the North Sea. A description of the key building blocks and the recent technology qualifications shall highlight the latest product development. Eventually, the main fabrication and installation steps shall be presented in view of a regional PLP application. A regional business case comparing the three water injection corrosion approaches shall highlight the typical economic metrics that could be achieved thanks to the use of PLP technology.\u0000 Today, this technology is accessible to operators in the Asia Pacific region with the recent opening of the Bintan Spoolbase in Indonesia enabling the deployment polymer lined water injection pipelines using the reel-lay method of installation. The strategic location of the spoolbase eliminates the significant intercontinental transit costs and the reel-lay method reduces offshore vessel days normally associated with conventional pipe-lay methods (S-lay and J-lay).","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81526119","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}
Casing and cement evaluation logging has long been essential for the success and safety of well operations from spud all the way through to abandonment. Indeed, as the casing and subsequent cement play such a critical role in the separation of fluids and the provision of downhole pressure barriers it is essential and sometimes also a regulatory requirement to obtain such data. For example, understanding the condition of the casing, whether it is worn or corroded, and the material in the annulus behind the casing, such as cement, fluid, formation or even gas directly plays into the success or otherwise and also the safety of multiple well operations. Historically this information has only been available from wireline conveyed tools. As a consequence of this other rig operations then have to stop to allow the wireline logging. It is also true to say that over the last few decades wells have become significantly more complex, more deviated and deeper. In addition, the pressure regimes have required tighter margins increasing the risk of operations and necessitating a greater need to understand the integrity of casing and cement barriers. As the wells have become deeper, more complex and more highly deviated it is also more difficult to run wireline conveyed tools, often significantly increasing the amount of time required to run and obtain this data. In fact, it can be clearly seen that increasingly, operators have often declined to get this critical data due to the time and effort required in certain circumstances to log on wireline. This has had a significant impact in terms of non productive time associated with not understanding the condition of casing and cement in well operations such as side tracking or cut and pull operations. For those associated with drilling then there has been a huge advancement in the technology, reliability and utilization of logging while drilling technology, although this has traditionally been employed in the openhole sections and deployed only while drilling. This paper will introduce a drillpipe conveyed casing and cement evaluation tool that can be deployed in parallel with other runs in the well to improve the efficiency of operations whilst also increasing the frequency of times that this data can be acquired. Through case history we will demonstrate how operators improved efficiency, reduced rigtime and personnel on board, improved the safety of operations and reduced the risk of non-productive time by the application of this new drillpipe conveyed technology.
{"title":"Casing and Cement Evaluation on Drillpipe: New Tool Acquires Well Integrity Data in Parallel with Existing Drillpipe Deplyed Operations from Drilling to Plug and Abandonment","authors":"A. Hawthorn, R. Steinsiek, Shaela Rahman","doi":"10.4043/31502-ms","DOIUrl":"https://doi.org/10.4043/31502-ms","url":null,"abstract":"\u0000 Casing and cement evaluation logging has long been essential for the success and safety of well operations from spud all the way through to abandonment. Indeed, as the casing and subsequent cement play such a critical role in the separation of fluids and the provision of downhole pressure barriers it is essential and sometimes also a regulatory requirement to obtain such data. For example, understanding the condition of the casing, whether it is worn or corroded, and the material in the annulus behind the casing, such as cement, fluid, formation or even gas directly plays into the success or otherwise and also the safety of multiple well operations. Historically this information has only been available from wireline conveyed tools. As a consequence of this other rig operations then have to stop to allow the wireline logging. It is also true to say that over the last few decades wells have become significantly more complex, more deviated and deeper. In addition, the pressure regimes have required tighter margins increasing the risk of operations and necessitating a greater need to understand the integrity of casing and cement barriers. As the wells have become deeper, more complex and more highly deviated it is also more difficult to run wireline conveyed tools, often significantly increasing the amount of time required to run and obtain this data. In fact, it can be clearly seen that increasingly, operators have often declined to get this critical data due to the time and effort required in certain circumstances to log on wireline. This has had a significant impact in terms of non productive time associated with not understanding the condition of casing and cement in well operations such as side tracking or cut and pull operations.\u0000 For those associated with drilling then there has been a huge advancement in the technology, reliability and utilization of logging while drilling technology, although this has traditionally been employed in the openhole sections and deployed only while drilling. This paper will introduce a drillpipe conveyed casing and cement evaluation tool that can be deployed in parallel with other runs in the well to improve the efficiency of operations whilst also increasing the frequency of times that this data can be acquired. Through case history we will demonstrate how operators improved efficiency, reduced rigtime and personnel on board, improved the safety of operations and reduced the risk of non-productive time by the application of this new drillpipe conveyed technology.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89974263","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}
B. N. Tackie-Otoo, Mohammed Abdalla Ayoub Mohammed, Muhammad Faiz Mohamad Ghani, S. Jufar, A. Hassan
Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is limited by various technical issues and environmental concerns. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. This study, therefore, focuses on investigating the potential of a "green" ASP formulation composed of monoethanolamine (ETA), sodium cocoyl alaninate (SCA) and Schizophyllan (SPG) for its enhanced oil recovery application. A conventional ASP formulation comprising sodium carbonate (Na2CO3), Sodium Dodecyl Sulfate (SDS) and partially hydrolyzed polyacrylamide (HPAM)was deployed for comparative purposes. The hardness tolerance of the green ASP shows that surfactant precipitation and scale formation could be mitigated. Lower surfactant concentration required to achieve low IFT and contact angle upon addition of alkali shows synergism in interfacial properties and wettability alteration. The ETA–SCA system yielded a better synergy in IFT reduction (minimum IFT of 4.73 × 10-2 mN/m) and wettability alteration (contact angle of 3° in 600 seconds) than the Na2CO3–SDS system (minimum IFT of 0.22 mN/m and contact angle of 5° in 600 seconds). Nevertheless, the conventional AS formulation exhibited better synergism with brine yielding minimum IFT of 1.52 × 10-2 mN/m. The ETA–SCA system also exhibited the ability to emulsify crude oil and form stable emulsions, a desirable property in chemical EOR processes. ETA had an insignificant impact on SPG's rheology, and the viscosity increased when SCA was added. The ETA–SCA–SPG solution showed shear thinning behavior at low shear rates. The oscillatory studies showed that both SPG and HPAM possess viscoelastic properties, with the green ASP retaining the viscoelasticity of SPG while HPAM loses its viscoelasticity in the presence of Na2CO3. SCA adsorption onto the sand surface was made unfavourable at a threshold of 0.3 wt% ETA. The green ASP formulation achieved an additional recovery of ~22%, while the conventional ASP formulation achieved ~19% additional recovery. Therefore, the green ASP formulation proves to have excellent oil recovery potential compounded by its environmentally benign nature.
{"title":"An Experimental Investigation into the Potential of a Green Alkali-Surfactant-Polymer Formulation for Enhanced Oil Recovery in Sandstone Reservoir","authors":"B. N. Tackie-Otoo, Mohammed Abdalla Ayoub Mohammed, Muhammad Faiz Mohamad Ghani, S. Jufar, A. Hassan","doi":"10.4043/31505-ms","DOIUrl":"https://doi.org/10.4043/31505-ms","url":null,"abstract":"\u0000 Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is limited by various technical issues and environmental concerns. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. This study, therefore, focuses on investigating the potential of a \"green\" ASP formulation composed of monoethanolamine (ETA), sodium cocoyl alaninate (SCA) and Schizophyllan (SPG) for its enhanced oil recovery application. A conventional ASP formulation comprising sodium carbonate (Na2CO3), Sodium Dodecyl Sulfate (SDS) and partially hydrolyzed polyacrylamide (HPAM)was deployed for comparative purposes.\u0000 The hardness tolerance of the green ASP shows that surfactant precipitation and scale formation could be mitigated. Lower surfactant concentration required to achieve low IFT and contact angle upon addition of alkali shows synergism in interfacial properties and wettability alteration. The ETA–SCA system yielded a better synergy in IFT reduction (minimum IFT of 4.73 × 10-2 mN/m) and wettability alteration (contact angle of 3° in 600 seconds) than the Na2CO3–SDS system (minimum IFT of 0.22 mN/m and contact angle of 5° in 600 seconds). Nevertheless, the conventional AS formulation exhibited better synergism with brine yielding minimum IFT of 1.52 × 10-2 mN/m. The ETA–SCA system also exhibited the ability to emulsify crude oil and form stable emulsions, a desirable property in chemical EOR processes. ETA had an insignificant impact on SPG's rheology, and the viscosity increased when SCA was added. The ETA–SCA–SPG solution showed shear thinning behavior at low shear rates. The oscillatory studies showed that both SPG and HPAM possess viscoelastic properties, with the green ASP retaining the viscoelasticity of SPG while HPAM loses its viscoelasticity in the presence of Na2CO3. SCA adsorption onto the sand surface was made unfavourable at a threshold of 0.3 wt% ETA. The green ASP formulation achieved an additional recovery of ~22%, while the conventional ASP formulation achieved ~19% additional recovery. Therefore, the green ASP formulation proves to have excellent oil recovery potential compounded by its environmentally benign nature.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73010118","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}
Stephen Duffy, Nick Wasuthalainunt, Chanikarn Wongnang
The objective of this paper is to demonstrate the improved drilling performance achieved by operators in the Asia Pacific region by implementing shaped Polycrystalline diamond compact (PDC) cutter technology. The success of these PDC bit designs is achieved using a design process augmented by advanced drilling simulations to optimize cutter placement specifically for the formations present in the region. For decades the drilling industry has been aware of the potential performance gains, in certain targeted formations, by forming cylindrical cutters into other geometrical shapes. These early generation shaped cutters had limited success due to diamond technology, along with the high manufacturing costs associated with shaping the cutters. Recently, PDC drill bits with shaped cutter designs are becoming more prolific in particular formation types. A number of these formations targeted for improved drilling performance are present in the Asia Pacific region. This paper describes a unique advanced drilling simulation software that has been calibrated with data recorded from various pressurized drilling tests in specific rock types in the drilling lab. It also explores the new design processes that integrates these advanced drilling simulations against historical drilling data and aids in the down selection of design concepts. This new process has been used by application engineers in the Asia Pacific region and supported by a global service delivery team to optimize shaped PDC cutter bit designs. Improved drilling performance is achieved with the correct application of shaped PDC cutter technology. Case studies from the Asia Pacific region demonstrate how shaped cutter PDC designs allowed operators in China and Brunei to improve drilling performance. For example, a Brunei operator doubled the rate of penetration previous seen in these targeted applications. In South West China, longer footage and rate of penetration (ROP) improvements have been achieved. In North West China, 30% ROP improvements have been observed. This novel design process enables performance driven design decisions with minimal need to iterate in the field, providing the operator with an optimal design to suit their needs.
{"title":"Improved Drilling Performance in Asia Pacific Formations Through Digitally Augmented Design Process for Shaped Cutter Drill Bits","authors":"Stephen Duffy, Nick Wasuthalainunt, Chanikarn Wongnang","doi":"10.4043/31346-ms","DOIUrl":"https://doi.org/10.4043/31346-ms","url":null,"abstract":"\u0000 The objective of this paper is to demonstrate the improved drilling performance achieved by operators in the Asia Pacific region by implementing shaped Polycrystalline diamond compact (PDC) cutter technology. The success of these PDC bit designs is achieved using a design process augmented by advanced drilling simulations to optimize cutter placement specifically for the formations present in the region. For decades the drilling industry has been aware of the potential performance gains, in certain targeted formations, by forming cylindrical cutters into other geometrical shapes. These early generation shaped cutters had limited success due to diamond technology, along with the high manufacturing costs associated with shaping the cutters. Recently, PDC drill bits with shaped cutter designs are becoming more prolific in particular formation types. A number of these formations targeted for improved drilling performance are present in the Asia Pacific region.\u0000 This paper describes a unique advanced drilling simulation software that has been calibrated with data recorded from various pressurized drilling tests in specific rock types in the drilling lab. It also explores the new design processes that integrates these advanced drilling simulations against historical drilling data and aids in the down selection of design concepts. This new process has been used by application engineers in the Asia Pacific region and supported by a global service delivery team to optimize shaped PDC cutter bit designs.\u0000 Improved drilling performance is achieved with the correct application of shaped PDC cutter technology. Case studies from the Asia Pacific region demonstrate how shaped cutter PDC designs allowed operators in China and Brunei to improve drilling performance. For example, a Brunei operator doubled the rate of penetration previous seen in these targeted applications. In South West China, longer footage and rate of penetration (ROP) improvements have been achieved. In North West China, 30% ROP improvements have been observed.\u0000 This novel design process enables performance driven design decisions with minimal need to iterate in the field, providing the operator with an optimal design to suit their needs.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76164665","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}
Zhen-Xuan Yew, Monthathip Kosolpinete, T. Lerdsuwankij, G. Sen, M. F. Harun, T. Duangprasert, L. Noomee, Jeerisuda Thongseng, Thanitha Wongsawat
The study emphasized on a collaborative work across various domains to improve reserve estimation utilizing integrated analysis from geological understanding, seismic interpretation, petrophysical log to sampled pressure and production data. A cross-disciplined approach was tailored for this complex marginal field and it included a fast loop full-field reservoir modeling and simulation to delineate the reservoir characteristics in a timely manner. The study improves the confidence level in reserve estimation of the field with a range of 30-35% primary recovery factor interpreted across different sands which is in line with other publications that in a typical Gulf of Thailand oil reservoir, in the presence of a strong water drive, the most likely primary recovery factor is between 18-40%, depending on the thickness of the oil column, bottom water versus edge water and the presence of a gas cap. The study helps to drive real field decision making for upcoming drilling campaigns to further improve the economic life of the field. This paper presents a fit-for-purpose reservoir modeling while drilling approach demonstrating how the company used newly drilled well data to validate the reservoir model and to drive new decisions for field development planning. The industry has limited published case studies on medium to heavy oil (19 to 25 degree API) with strong aquifer support in the region of onshore Thailand. This case study presents an approach in addressing multiple challenges faced to unlock the high oil potential of the region. In summary, a cross-disciplined, fit-for-purpose and practical approach using latest available commercial technology enabled real-field decisions being made timely and accurately. Similar approach will be undertaken in other fields of the company in the region.
{"title":"L53-DD, On-Shore Thailand a Case Study of Integrated Geoscience to Engineering Approach Improving Reserve Estimation and Field Development Planning","authors":"Zhen-Xuan Yew, Monthathip Kosolpinete, T. Lerdsuwankij, G. Sen, M. F. Harun, T. Duangprasert, L. Noomee, Jeerisuda Thongseng, Thanitha Wongsawat","doi":"10.4043/31381-ms","DOIUrl":"https://doi.org/10.4043/31381-ms","url":null,"abstract":"\u0000 The study emphasized on a collaborative work across various domains to improve reserve estimation utilizing integrated analysis from geological understanding, seismic interpretation, petrophysical log to sampled pressure and production data. A cross-disciplined approach was tailored for this complex marginal field and it included a fast loop full-field reservoir modeling and simulation to delineate the reservoir characteristics in a timely manner.\u0000 The study improves the confidence level in reserve estimation of the field with a range of 30-35% primary recovery factor interpreted across different sands which is in line with other publications that in a typical Gulf of Thailand oil reservoir, in the presence of a strong water drive, the most likely primary recovery factor is between 18-40%, depending on the thickness of the oil column, bottom water versus edge water and the presence of a gas cap. The study helps to drive real field decision making for upcoming drilling campaigns to further improve the economic life of the field. This paper presents a fit-for-purpose reservoir modeling while drilling approach demonstrating how the company used newly drilled well data to validate the reservoir model and to drive new decisions for field development planning.\u0000 The industry has limited published case studies on medium to heavy oil (19 to 25 degree API) with strong aquifer support in the region of onshore Thailand. This case study presents an approach in addressing multiple challenges faced to unlock the high oil potential of the region. In summary, a cross-disciplined, fit-for-purpose and practical approach using latest available commercial technology enabled real-field decisions being made timely and accurately. Similar approach will be undertaken in other fields of the company in the region.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81045292","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}
Syarifah Puteh Mariah Syed Abd Rahim, M. F. Azman, Zaidi Awang@Mohamed, Mior Yusni Ahmad
Marginal field development commonly face setback when it comes to an investment decision, which makes it technically and commercially very challenging to be developed. Technologies that usually applied in big fields may not be economically relevant to the marginal fields, despite require the same assurance and functionality. Well completion cost itself can take up to 50% of the total well cost, especially for fields that potentially must deal with sand production, high CO2 and/or H2S content, artificial lift, and multilayer zonal completion and isolation. This paper demonstrates an integrated approach to identify and define the optimum well completion strategy for such conditions in a Malaysian oilfield. The first step is to list all the operational issues and challenges of producing from the neighboring fault block and other analogue fields experience. Leveraging on the available data and types of completion that have been installed, a set of scoring is given to different completion type, considering the sand production control effectiveness, good well performance, and long well life span. The shortlisted completion types were further evaluated based on the following criteria: Production flexibility Early monetization Operation complexity (drilling and completion) Sand production management Sand control failure probability Associated Risks Stand-alone economic As a result, eight (8) completion strategies were investigated namely Monobore, Monobore wih resin, Cased & Perf, Cased & Perf with resin, Open Hole Stand Alone Screen (OHSAS), Cased-Hole Stand Alone Screen (CHSAS), Cased-Hole Gravel Pack (CHGP); using circulating method or frac pack. Different completion has its own advantages and disadvantages. Structured scoring system was again applied to guide the decision-making process. The key elements in the decision thought process are the associated cost of each option, the skin factor that affect the production and reserve estimation, and ultimately the Net Present Value (NPV) indicator. In conclusion, identifying the optimum well completion will never give a single solution answer. However, the most important thing is to consider all the decisive factors and properly evaluate all options. In our own real example, the option that gives the best NPV coupled with tolerable risk (HSE risk i.e. less issue at surface) was selected as the optimum well completion strategy to be used in the development plan.
{"title":"Defining the Optimum Well Completion for Marginal Field Development – An Approach","authors":"Syarifah Puteh Mariah Syed Abd Rahim, M. F. Azman, Zaidi Awang@Mohamed, Mior Yusni Ahmad","doi":"10.4043/31552-ms","DOIUrl":"https://doi.org/10.4043/31552-ms","url":null,"abstract":"\u0000 Marginal field development commonly face setback when it comes to an investment decision, which makes it technically and commercially very challenging to be developed. Technologies that usually applied in big fields may not be economically relevant to the marginal fields, despite require the same assurance and functionality. Well completion cost itself can take up to 50% of the total well cost, especially for fields that potentially must deal with sand production, high CO2 and/or H2S content, artificial lift, and multilayer zonal completion and isolation. This paper demonstrates an integrated approach to identify and define the optimum well completion strategy for such conditions in a Malaysian oilfield.\u0000 The first step is to list all the operational issues and challenges of producing from the neighboring fault block and other analogue fields experience. Leveraging on the available data and types of completion that have been installed, a set of scoring is given to different completion type, considering the sand production control effectiveness, good well performance, and long well life span. The shortlisted completion types were further evaluated based on the following criteria:\u0000 Production flexibility Early monetization Operation complexity (drilling and completion) Sand production management Sand control failure probability Associated Risks Stand-alone economic\u0000 As a result, eight (8) completion strategies were investigated namely Monobore, Monobore wih resin, Cased & Perf, Cased & Perf with resin, Open Hole Stand Alone Screen (OHSAS), Cased-Hole Stand Alone Screen (CHSAS), Cased-Hole Gravel Pack (CHGP); using circulating method or frac pack. Different completion has its own advantages and disadvantages. Structured scoring system was again applied to guide the decision-making process. The key elements in the decision thought process are the associated cost of each option, the skin factor that affect the production and reserve estimation, and ultimately the Net Present Value (NPV) indicator.\u0000 In conclusion, identifying the optimum well completion will never give a single solution answer. However, the most important thing is to consider all the decisive factors and properly evaluate all options. In our own real example, the option that gives the best NPV coupled with tolerable risk (HSE risk i.e. less issue at surface) was selected as the optimum well completion strategy to be used in the development plan.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81098063","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}
Cementing is an important link in the process of oil and gas well construction. The quality of cementing directly affects the safety of next drilling, recovery capacity and life of later production. It is very important to accurately reflect and describe the dynamic changes of various underground parameters in the process of cementing for reasonable control of construction measures and guarantee the quality of cementing replacement. Based on the study of the dynamic process of cementing, the field equation is simplified to ID model by using the principle of momentum conservation and mass conservation, and the calculation model of cementing dynamic parameters at any time considering the effect of U-shaped pipe is established, including bottom hole pressure, friction, height and volume of vacuum section, static pressure in pipe and annulus, ECD and other dynamic parameters. The initial value problem is solved numerically by iterative method. The software of cement slurry flow simulator is developed, which is used to visually simulate the cement slurry flow process. The numerical model development software can be used to visually simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection. It can simulate the whole flow process of cement injection well, including the generation of U-tube effect, and analyze the variation law of dynamic parameters. The software can be used to simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection including the generation of U-tube effect, and analyze the variation law of dynamic parameters. Field data of a well was verified, and the results show that the proposed method can accurately calculate the flow parameters in the whole process of cementing, and can be used to guide the design of cementing operation. The innovation of this paper is to develop the simulation software of cementing slurry dynamic process. The function modules of the software use numerical model instead of empirical formula to improve the calculation accuracy of each parameter. The software has comprehensive functions, and gives the dynamic parameter change law of each stage in the fixed construction process. It has strong practicability and can well meet the requirements of on-site construction.
{"title":"Numerical Simulation of Whole Process Flow of Cementing Slurry","authors":"Shanshan Liu, Rui Li, W. Yuan","doi":"10.4043/31551-ms","DOIUrl":"https://doi.org/10.4043/31551-ms","url":null,"abstract":"\u0000 Cementing is an important link in the process of oil and gas well construction. The quality of cementing directly affects the safety of next drilling, recovery capacity and life of later production. It is very important to accurately reflect and describe the dynamic changes of various underground parameters in the process of cementing for reasonable control of construction measures and guarantee the quality of cementing replacement. Based on the study of the dynamic process of cementing, the field equation is simplified to ID model by using the principle of momentum conservation and mass conservation, and the calculation model of cementing dynamic parameters at any time considering the effect of U-shaped pipe is established, including bottom hole pressure, friction, height and volume of vacuum section, static pressure in pipe and annulus, ECD and other dynamic parameters. The initial value problem is solved numerically by iterative method. The software of cement slurry flow simulator is developed, which is used to visually simulate the cement slurry flow process. The numerical model development software can be used to visually simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection. It can simulate the whole flow process of cement injection well, including the generation of U-tube effect, and analyze the variation law of dynamic parameters. The software can be used to simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection including the generation of U-tube effect, and analyze the variation law of dynamic parameters. Field data of a well was verified, and the results show that the proposed method can accurately calculate the flow parameters in the whole process of cementing, and can be used to guide the design of cementing operation. The innovation of this paper is to develop the simulation software of cementing slurry dynamic process. The function modules of the software use numerical model instead of empirical formula to improve the calculation accuracy of each parameter. The software has comprehensive functions, and gives the dynamic parameter change law of each stage in the fixed construction process. It has strong practicability and can well meet the requirements of on-site construction.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86807954","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}
A. L. Ismail, M. A. Za'ba, Mondali Mondali, Azah Ismail, M. I. Idris, M. F. Ishak
Borehole survey is a very crucial element in drilling a well. The data will be utilized during all phases of drilling campaign – planning, execution, and post drilling. During planning, borehole survey data are critical to avoid well collision with nearby well. It is done through correct survey of offset data and correct toolcode assigned to the survey program together with database QAQC. While actual drilling itself, the survey will be closely monitored to ensure that the well is clear from any collision risk. The survey will guide the directional driller to steer to the geological objectives and hit the geological target with high confidence. Finally, once drilling has been completed, the survey data will be tied in to geological and reservoir models and to be used for planning of future campaign. Since the last forty years, measurement while drilling (MWD) surveys have been the backbone for the borehole surveying. MWD surveys are in fact a measurement/surveying while static condition not during online drilling itself. Industry has experienced multiple evolution of MWD surveys, but none of the evolutions lead to the survey in dynamic conditions. Realizing the true potentials of getting the survey data in dynamic condition, it will help the rigsite operation to minimize the risk associated with longer stationary time. With this definitive dynamic survey while drilling can accurately be taken while drilling, moving, rotating and sliding, it had proven to eliminate the survey-related rig time per survey and reduced associated drilling risks, therefore improves the overall drilling efficiency. The service incorporates the new telemetry innovations that enables up to 20bps and the advance drilling dynamics design includes three-axis shock and vibration and turbine power. Additionally, geological accuracy is refined using gamma ray and electromagnetic resistivity in combination with continuous six-axis direction and inclination sensors. The deployment of this dynamic-survey-while drilling service had enable the operator to acquire precise BHA location data at a higher frequency during drilling for improved decision making, eleiminating up to 15 min of survey-related rig time per survey. This also eliminated the need for additional pump cycles along with their associated washouts, stuck pipe risks and other directional drilling difficulties. The ultimate yield is definitive dynamic surveys, delivering real-time borehole conditions that reduce time to TD. This paper also covers the advance procedure of taking definitive non-static survey. The challenge is to ensure the non-static data to be sent continuously and meet survey acceptance criteria. Hence, the continuous survey data can be qualified as definitive survey and assigned a proper toolcode. To validate this continuous survey measurements, the author analyses the survey comparison with conventional static survey and gyroscopic survey results in the field test runs. The author will then presen
{"title":"Improvement in Drilling Efficiency by Eliminating Static Survey Time","authors":"A. L. Ismail, M. A. Za'ba, Mondali Mondali, Azah Ismail, M. I. Idris, M. F. Ishak","doi":"10.4043/31445-ms","DOIUrl":"https://doi.org/10.4043/31445-ms","url":null,"abstract":"\u0000 Borehole survey is a very crucial element in drilling a well. The data will be utilized during all phases of drilling campaign – planning, execution, and post drilling. During planning, borehole survey data are critical to avoid well collision with nearby well. It is done through correct survey of offset data and correct toolcode assigned to the survey program together with database QAQC. While actual drilling itself, the survey will be closely monitored to ensure that the well is clear from any collision risk. The survey will guide the directional driller to steer to the geological objectives and hit the geological target with high confidence. Finally, once drilling has been completed, the survey data will be tied in to geological and reservoir models and to be used for planning of future campaign.\u0000 Since the last forty years, measurement while drilling (MWD) surveys have been the backbone for the borehole surveying. MWD surveys are in fact a measurement/surveying while static condition not during online drilling itself. Industry has experienced multiple evolution of MWD surveys, but none of the evolutions lead to the survey in dynamic conditions. Realizing the true potentials of getting the survey data in dynamic condition, it will help the rigsite operation to minimize the risk associated with longer stationary time. With this definitive dynamic survey while drilling can accurately be taken while drilling, moving, rotating and sliding, it had proven to eliminate the survey-related rig time per survey and reduced associated drilling risks, therefore improves the overall drilling efficiency.\u0000 The service incorporates the new telemetry innovations that enables up to 20bps and the advance drilling dynamics design includes three-axis shock and vibration and turbine power. Additionally, geological accuracy is refined using gamma ray and electromagnetic resistivity in combination with continuous six-axis direction and inclination sensors. The deployment of this dynamic-survey-while drilling service had enable the operator to acquire precise BHA location data at a higher frequency during drilling for improved decision making, eleiminating up to 15 min of survey-related rig time per survey. This also eliminated the need for additional pump cycles along with their associated washouts, stuck pipe risks and other directional drilling difficulties. The ultimate yield is definitive dynamic surveys, delivering real-time borehole conditions that reduce time to TD.\u0000 This paper also covers the advance procedure of taking definitive non-static survey. The challenge is to ensure the non-static data to be sent continuously and meet survey acceptance criteria. Hence, the continuous survey data can be qualified as definitive survey and assigned a proper toolcode. To validate this continuous survey measurements, the author analyses the survey comparison with conventional static survey and gyroscopic survey results in the field test runs. The author will then presen","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90518959","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}
A. Hassan, M. Ayoub, Mysara E. Mohyadinn, E. Al-Shalabi, F. Alakbari
The smart water-assisted foam (SWAF) technology is a novel enhanced oil recovery (EOR) technique, which combines the synergistic effect of both smart water and foam-flooding methods. The smart water enables multilevel improvements, namely, stabilization of foam-lamella and wettability alteration of the carbonate rock, which leads to desirable oil relative-permeability behavior. Contact angle tests are the common approach for measurement of the preferential affinity of reservoir rocks to fluids. However, the laboratory methods for contact angle measurement are costly and time-consuming. Therefore, in this study, we propose a new approach to predict contact angle based on a machine learning technique. A model based on artificial neural network (ANN) algorithm was developed using 1615 datasets acquired from diverse published resources. The developed ANN-based model to predict contact angle was further evaluated by applying the trend analysis approach, which verify the correct relationships between the inputs and output parameters. The collected datasets were trifurcated into training, validation, and testing segments, so that the over-fitting and under-fitting issues are evaded. Furthermore, some statistical error analyses, namely, the average absolute percentage relative error (AAPRE), and the correlation coefficient (R) were performed to present the robustness and accuracy of the proposed model. The findings from the trend analysis showed the sound relationships between the inputs and output parameters. The statistical error analyses proved that the developed ANN-based model does not have any under-fitting or overfitting anomalies, and correctly determines the contact angle with high accuracy, substantiated by the R values of 0.9988, 0.9985, 0.9967, and AAPRE values of 1.68, 1.62, 1.81, for training, validation, and testing datasets, respectively. The proposed ANN-based model for contact angle prediction has many advantages including speed, reliability, and ease of usage. This work highlights the potential of machine learning algorithms in oil and gas applications, particularly in contact angle prediction from SWAF technology. The findings from this study are expected to add valuable insights into identifying the optimal conditions (i.e., optimum smart water and surfactant aqueous solution) for the operation sequence of SWAF technology, leading to successful field applications.
{"title":"A New Insight into Smart Water Assisted Foam SWAF Technology in Carbonate Rocks using Artificial Neural Networks ANNs","authors":"A. Hassan, M. Ayoub, Mysara E. Mohyadinn, E. Al-Shalabi, F. Alakbari","doi":"10.4043/31663-ms","DOIUrl":"https://doi.org/10.4043/31663-ms","url":null,"abstract":"\u0000 The smart water-assisted foam (SWAF) technology is a novel enhanced oil recovery (EOR) technique, which combines the synergistic effect of both smart water and foam-flooding methods. The smart water enables multilevel improvements, namely, stabilization of foam-lamella and wettability alteration of the carbonate rock, which leads to desirable oil relative-permeability behavior. Contact angle tests are the common approach for measurement of the preferential affinity of reservoir rocks to fluids. However, the laboratory methods for contact angle measurement are costly and time-consuming. Therefore, in this study, we propose a new approach to predict contact angle based on a machine learning technique. A model based on artificial neural network (ANN) algorithm was developed using 1615 datasets acquired from diverse published resources. The developed ANN-based model to predict contact angle was further evaluated by applying the trend analysis approach, which verify the correct relationships between the inputs and output parameters. The collected datasets were trifurcated into training, validation, and testing segments, so that the over-fitting and under-fitting issues are evaded. Furthermore, some statistical error analyses, namely, the average absolute percentage relative error (AAPRE), and the correlation coefficient (R) were performed to present the robustness and accuracy of the proposed model.\u0000 The findings from the trend analysis showed the sound relationships between the inputs and output parameters. The statistical error analyses proved that the developed ANN-based model does not have any under-fitting or overfitting anomalies, and correctly determines the contact angle with high accuracy, substantiated by the R values of 0.9988, 0.9985, 0.9967, and AAPRE values of 1.68, 1.62, 1.81, for training, validation, and testing datasets, respectively. The proposed ANN-based model for contact angle prediction has many advantages including speed, reliability, and ease of usage. This work highlights the potential of machine learning algorithms in oil and gas applications, particularly in contact angle prediction from SWAF technology. The findings from this study are expected to add valuable insights into identifying the optimal conditions (i.e., optimum smart water and surfactant aqueous solution) for the operation sequence of SWAF technology, leading to successful field applications.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89557519","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}
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