Xiaodong Han, L. Zhong, Qiuxia Wang, Wei Zhang, Jian Zou, Hao Liu, Hongyu Wang
Maximizing the future economic return of the asset is an important issue in petroleum engineering. For heavy oil reservoir developed with steam flooding, its production cost is much higher than that of conventional production methods. Commonly used parameters optimization method such as single factor analysis and orthogonal test cannot guarantee to obtain global optimal economic benefits. It is necessary and urgent to form a better optimization method to achieve higher profit. A new framework is proposed and presented to optimize well control parameters of both steam injection wells and oil production wells by integrating the reservoir simulator into the optimization algorithms. A net present value (NPV) formula for evaluation of horizontal well steam flooding project is proposed and the optimization objective is to maximize the NPV of production over the life. The generally acknowledged Particle swarm optimization (PSO) is used for solution of the optimization problem. This method has been tested for a typical offshore horizontal well steam flooding project. Results indicate that PSO gives good solutions for this problem and the following conclusions can be obtained. The NPV of the optimized project is improved and larger than the NPV of its initial guess. The control frequency has great influence on the optimal NPV, and the optimal NPV increases with the increase of the control frequency. Steam injection and oil production rates need to be controlled and decreased at the latter stage for mitigating ineffective steam cycle between injection and production wells. The new method has been used for well control optimization of the first offshore horizontal well steam flooding pilot and this method would which will provide powerful technical support for the high efficiency development of the heavy oil resource with steam flooding.
{"title":"Well Control Optimization of Offshore Horizontal Steam Flooding Wells Using Artificial Intelligence Algorithm","authors":"Xiaodong Han, L. Zhong, Qiuxia Wang, Wei Zhang, Jian Zou, Hao Liu, Hongyu Wang","doi":"10.4043/31466-ms","DOIUrl":"https://doi.org/10.4043/31466-ms","url":null,"abstract":"\u0000 Maximizing the future economic return of the asset is an important issue in petroleum engineering. For heavy oil reservoir developed with steam flooding, its production cost is much higher than that of conventional production methods. Commonly used parameters optimization method such as single factor analysis and orthogonal test cannot guarantee to obtain global optimal economic benefits. It is necessary and urgent to form a better optimization method to achieve higher profit.\u0000 A new framework is proposed and presented to optimize well control parameters of both steam injection wells and oil production wells by integrating the reservoir simulator into the optimization algorithms. A net present value (NPV) formula for evaluation of horizontal well steam flooding project is proposed and the optimization objective is to maximize the NPV of production over the life. The generally acknowledged Particle swarm optimization (PSO) is used for solution of the optimization problem. This method has been tested for a typical offshore horizontal well steam flooding project. Results indicate that PSO gives good solutions for this problem and the following conclusions can be obtained. The NPV of the optimized project is improved and larger than the NPV of its initial guess. The control frequency has great influence on the optimal NPV, and the optimal NPV increases with the increase of the control frequency. Steam injection and oil production rates need to be controlled and decreased at the latter stage for mitigating ineffective steam cycle between injection and production wells.\u0000 The new method has been used for well control optimization of the first offshore horizontal well steam flooding pilot and this method would which will provide powerful technical support for the high efficiency development of the heavy oil resource with steam flooding.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85778602","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}
Sharizal bin Amurol Jamal, Tiing-Poh Hii, Zhili Ang, Kenneth Yip, Tee Bin Lim
Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign. The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions. This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.
{"title":"Implementation of Key Risk Mitigation Strategies and Learnings Enabling Successful Efficient Execution in Malikai Phase 2 Project Mooring Campaigns","authors":"Sharizal bin Amurol Jamal, Tiing-Poh Hii, Zhili Ang, Kenneth Yip, Tee Bin Lim","doi":"10.4043/31397-ms","DOIUrl":"https://doi.org/10.4043/31397-ms","url":null,"abstract":"\u0000 Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign.\u0000 The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions.\u0000 This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75448380","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}
R. Sinaga, Kristoforus Widyas Tokoh, Tomi Sugiarto, R. Hutahaean, Muhammad Masrur, Mochamad Syafrudin, Ferdian Ferdian, Yosafat Solagratia, M. Maharanoe
In the last 2 (two) years, the operator has been performing gravel pack (GP) completion using a Hydraulic Workover Unit (HWU). Such rigless GP explains that a drilling rig shall drill a well, running the casing and cementing then suspending the well. Next, HWU will perform the completion job to fulfill the scope of the well construction. By May 2021, HWU has done 4 (four) rigless GP with various well designs. The original background is to reduce costs of the well construction and to increase the wells delivery efficiency of a jack-up rig. This paper will compare the duration of rigless GP execution in those wells, even though the value creation of using HWU as an alternative way will also be reviewed. Regarding operational capabilities, HWU has several limitations that differ from a jack-up rig. Several disadvantages range from HWU's construction, tripping performance, lifting practices until contract management. From a construction aspect, HWU is more sensitive to weather thus prone to the operation suspension. In some platforms, HWU has more complexity lifting operations due to the crane's reach limitation, therefore an additional crane is needed to assist. Furthermore, HWU utilizes traveling slips for tripping, as such the length of the cylinder will affect the speed. Moreover, HWU is not in a favorable situation due to some important services are not dedicated to support the operation. For example, the handling equipment for upper completion is managed through a call-out contract and the logistic vessel has to be shared with other fleets. Therefore, it is essential to develop a solid course of action to achieve the objective of utilizing HWU in GP jobs. Related to performance enhancement, some initiatives have been pursued i.e. changing the position of the barge to reduce weather sensitivity, developing the effective logistic plan, and managing some activities to be performed by the jack-up rig (in offline mode). Moreover, adding some pipe racks and enforcing all crew to improve tripping speed safely are also part of the improvement. Also, it is essential to select the equipment as necessary as possible to deal with the call-out contract and to increase the economic value of the project. Finally, performance monitoring and documenting lesson learned are critical to pursue for future improvement. All of those efforts have been paid off as indicated by the learning curve which has been shaped. Referring to the duration and expenses of the first rig-less GP job, the latest well has attained a reduction in costs by 60% and less 66% of time completion. The fact implies that HWU is worth pursuing in executing GP completions as an alternative to the conventional way.
{"title":"Evaluation of Utilisation a Hydraulic Workover Unit for Gravel Pack Job in Indonesia","authors":"R. Sinaga, Kristoforus Widyas Tokoh, Tomi Sugiarto, R. Hutahaean, Muhammad Masrur, Mochamad Syafrudin, Ferdian Ferdian, Yosafat Solagratia, M. Maharanoe","doi":"10.4043/31375-ms","DOIUrl":"https://doi.org/10.4043/31375-ms","url":null,"abstract":"\u0000 In the last 2 (two) years, the operator has been performing gravel pack (GP) completion using a Hydraulic Workover Unit (HWU). Such rigless GP explains that a drilling rig shall drill a well, running the casing and cementing then suspending the well. Next, HWU will perform the completion job to fulfill the scope of the well construction. By May 2021, HWU has done 4 (four) rigless GP with various well designs. The original background is to reduce costs of the well construction and to increase the wells delivery efficiency of a jack-up rig. This paper will compare the duration of rigless GP execution in those wells, even though the value creation of using HWU as an alternative way will also be reviewed.\u0000 Regarding operational capabilities, HWU has several limitations that differ from a jack-up rig. Several disadvantages range from HWU's construction, tripping performance, lifting practices until contract management. From a construction aspect, HWU is more sensitive to weather thus prone to the operation suspension. In some platforms, HWU has more complexity lifting operations due to the crane's reach limitation, therefore an additional crane is needed to assist. Furthermore, HWU utilizes traveling slips for tripping, as such the length of the cylinder will affect the speed. Moreover, HWU is not in a favorable situation due to some important services are not dedicated to support the operation. For example, the handling equipment for upper completion is managed through a call-out contract and the logistic vessel has to be shared with other fleets. Therefore, it is essential to develop a solid course of action to achieve the objective of utilizing HWU in GP jobs.\u0000 Related to performance enhancement, some initiatives have been pursued i.e. changing the position of the barge to reduce weather sensitivity, developing the effective logistic plan, and managing some activities to be performed by the jack-up rig (in offline mode). Moreover, adding some pipe racks and enforcing all crew to improve tripping speed safely are also part of the improvement. Also, it is essential to select the equipment as necessary as possible to deal with the call-out contract and to increase the economic value of the project. Finally, performance monitoring and documenting lesson learned are critical to pursue for future improvement.\u0000 All of those efforts have been paid off as indicated by the learning curve which has been shaped.\u0000 Referring to the duration and expenses of the first rig-less GP job, the latest well has attained a reduction in costs by 60% and less 66% of time completion. The fact implies that HWU is worth pursuing in executing GP completions as an alternative to the conventional way.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"190 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72789570","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 novel apparent permeability model of shale gas is derived considering the stress dependence, the thickness of adsorbed layer, slip flow, Knudsen diffusion and surface diffusion. The thickness of the adsorbed layer is derived according to the porosity occupied by the adsorbed phase in the capillary model. Consequently, the impact of the adsorbed layer and its change with the pressure on apparent permeability can be clearly revealed in the novel model in ultramicropores, or micropores, or mesopores, or macropores. With the stress dependence and the thickness of adsorbed layer considered simultaneously, the effective hole radius is substantiated to be smaller than the original hole radius to a certain degree. On account of this, the ratio of apparent permeability to the intrinsic permeability computed by the novel model is a lot distinct from the existing models. As the pressure increases, the ratio in the novel model declines from above 1 to below 1, followed by a slight upward trend. However, the ratio in other models drops all the way and yet remains above 1 as the pressure rises. Finally, the impact factors of permeability, including stress dependence coefficient, hole radius, reservoir pressure, Langmuir volume and Langmuir pressure, are analyzed. The contribution of slip flow, Knudsen diffusion and surface diffusion to apparent permeability is also illustrated.
{"title":"A Novel Apparent Permeability Model in Shale Gas Reservoirs","authors":"Lang He, Bin Yang, Jing Liu, Xinyue Na, Yang Ge","doi":"10.4043/31471-ms","DOIUrl":"https://doi.org/10.4043/31471-ms","url":null,"abstract":"\u0000 A novel apparent permeability model of shale gas is derived considering the stress dependence, the thickness of adsorbed layer, slip flow, Knudsen diffusion and surface diffusion. The thickness of the adsorbed layer is derived according to the porosity occupied by the adsorbed phase in the capillary model. Consequently, the impact of the adsorbed layer and its change with the pressure on apparent permeability can be clearly revealed in the novel model in ultramicropores, or micropores, or mesopores, or macropores. With the stress dependence and the thickness of adsorbed layer considered simultaneously, the effective hole radius is substantiated to be smaller than the original hole radius to a certain degree. On account of this, the ratio of apparent permeability to the intrinsic permeability computed by the novel model is a lot distinct from the existing models. As the pressure increases, the ratio in the novel model declines from above 1 to below 1, followed by a slight upward trend. However, the ratio in other models drops all the way and yet remains above 1 as the pressure rises. Finally, the impact factors of permeability, including stress dependence coefficient, hole radius, reservoir pressure, Langmuir volume and Langmuir pressure, are analyzed. The contribution of slip flow, Knudsen diffusion and surface diffusion to apparent permeability is also illustrated.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76791497","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}
Stratigraphic forward modeling (SFM) is an innovative approach to subsurface facies prediction at the basin scale that augments and overcomes some of the limitations of conventional seismic, well, and analog data. As a multidisciplinary approach to play characterization, SFM improves the efficiency of current workflows, which is important given the current downward pressure on capex in oil and gas companies. A 2D SFM study on data from Browse basin, NW Australia, was conducted to enhance the prediction of facies distribution and improve play characterization by integrating SFM with other disciplines. The work started with seismic interpretation and depth conversion. Then, a third to fourth-order sequence stratigraphy interpretation was performed to determine the main sequence boundaries, maximum flooding surfaces, and a relative sea-level curve. The sequence stratigraphy results were later used to infer some of the inputs and parameters of the SFM model. The model simulates the deposition of clastic and carbonates from the Turonian (Late Cretaceous) to the present day. The results from the model were used to validate some of the geological concepts and the seismic interpretation. In addition, the approach enabled the prediction of reservoir quality, reservoir distribution, the presence of the seal, and the quantification of erosion. A 2D petroleum system model (PSM) covering the area from the Yampi shelf to the Seringapatam sub-basin was built using seismic interpretation, regional tectonic information, source rock geochemistry, and paleo heat flow. The results from SFM were integrated into a 2D PSM by resampling facies and erosion properties for each of the finely subdivided layers. The high-resolution 2D PSM with refined facies was simulated in geological time to model the basin evolution and its impact on all elements and processes of the petroleum system of Browse basin, which have been validated with nearby fields. As a result of this integrated approach, the risk of charge and entrapment in prospective stratigraphic traps was better understood and quantified. In addition, this approach helped to increase yet-to-find (YTF) hydrocarbon resources by accurately predicting reservoir distribution and extent. The generation of a 2D SFM and its integration within a multidisciplinary approach to predict facies represents a novel addition to exploration workflows. Adopting such an approach can improve significantly on the understanding of hydrocarbon entrapment and further reduce exploration risks.
{"title":"Towards a Multidisciplinary Approach in Play Characterisation: An Integrated Case Study from Browse Basin, NW Shelf, Australia","authors":"Wael Ben Habel, S. Dubey","doi":"10.4043/31603-ms","DOIUrl":"https://doi.org/10.4043/31603-ms","url":null,"abstract":"\u0000 Stratigraphic forward modeling (SFM) is an innovative approach to subsurface facies prediction at the basin scale that augments and overcomes some of the limitations of conventional seismic, well, and analog data. As a multidisciplinary approach to play characterization, SFM improves the efficiency of current workflows, which is important given the current downward pressure on capex in oil and gas companies.\u0000 A 2D SFM study on data from Browse basin, NW Australia, was conducted to enhance the prediction of facies distribution and improve play characterization by integrating SFM with other disciplines. The work started with seismic interpretation and depth conversion. Then, a third to fourth-order sequence stratigraphy interpretation was performed to determine the main sequence boundaries, maximum flooding surfaces, and a relative sea-level curve. The sequence stratigraphy results were later used to infer some of the inputs and parameters of the SFM model. The model simulates the deposition of clastic and carbonates from the Turonian (Late Cretaceous) to the present day.\u0000 The results from the model were used to validate some of the geological concepts and the seismic interpretation. In addition, the approach enabled the prediction of reservoir quality, reservoir distribution, the presence of the seal, and the quantification of erosion. A 2D petroleum system model (PSM) covering the area from the Yampi shelf to the Seringapatam sub-basin was built using seismic interpretation, regional tectonic information, source rock geochemistry, and paleo heat flow. The results from SFM were integrated into a 2D PSM by resampling facies and erosion properties for each of the finely subdivided layers. The high-resolution 2D PSM with refined facies was simulated in geological time to model the basin evolution and its impact on all elements and processes of the petroleum system of Browse basin, which have been validated with nearby fields.\u0000 As a result of this integrated approach, the risk of charge and entrapment in prospective stratigraphic traps was better understood and quantified. In addition, this approach helped to increase yet-to-find (YTF) hydrocarbon resources by accurately predicting reservoir distribution and extent. The generation of a 2D SFM and its integration within a multidisciplinary approach to predict facies represents a novel addition to exploration workflows. Adopting such an approach can improve significantly on the understanding of hydrocarbon entrapment and further reduce exploration risks.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 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":"85300392","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}
Oil and gas drilling requires several components work simultaneously to ensure smooth and safe drilling. Drilling fluid or mud is an inseparable part of drilling oil and gas wells and circulated through out theh drilling operation. Drilling fluid contains a variety of additives or chemicals to provide various properties to drilling fluid namely viscosity, fluid loss control, emulsion stability, lubricity, etc. Developing environment friendly chemicals to provide the above-mentioned drilling fluid properties is a significant step taken towards sustainability and reducing carbon footprint besides suitability for aquifers and offshore environments. Several fatty acid-based chemicals used in drilling fluids as fatty acids offer eco-friendly and bio-degradable properties besides required drilling fluid properties. Vegatable oil contains triglycerides which is a potential source of fatty acids and their derivatives. Waste vegetable oil (WVO) provides a perpetual and sustainable source of raw material for various types of eco-friendly additives development. Waste vegetable oil is subjected to simple chemical modification of base hydrolysis process and mixtures of fatty acids have been obtained after finishing a sequence of clean-up process of reaction mixture. The fatty acids obtained are environment-friendly, bio-degradable and non-toxic. Due to technical, economic and environmental advantages of products derived from waste vegetable oils, we have undertaken several research projects to produce various chemicals from waste vegetable oil for oil and gas field applications. Fatty acid-based products mainly used in drilling fluids as lubricants to reduce torque and drag for water-based mud. In case of oil-based mud systems, fatty acid derived products are used as emulsifiers, wetting agents and rheology modifiers. However, these products have been either mixture of fatty acids and their derivatives or only derivatives of fatty acids. In our study, we have used the mixture of fatty acids obtained from chemical conversion of WVO for applications as lubricant for water-based mud and emulsifier and rheology modifier for invert emulsion oil-based mud systems. In this paper, we described the chemicals process for converting waste vegetable oil to fatty acids by base hydrolysis reaction in the first section. Application of synthesized fatty acids for water-based and oil-based mud formulation as lubricants, emulsifiers and rheology modifiers have been discussed in the second part of the paper.
{"title":"Sustainable and Green Drilling Fluid Additives Development","authors":"J. Ramasamy, Mohammad K. Arfaj","doi":"10.4043/31350-ms","DOIUrl":"https://doi.org/10.4043/31350-ms","url":null,"abstract":"\u0000 Oil and gas drilling requires several components work simultaneously to ensure smooth and safe drilling. Drilling fluid or mud is an inseparable part of drilling oil and gas wells and circulated through out theh drilling operation. Drilling fluid contains a variety of additives or chemicals to provide various properties to drilling fluid namely viscosity, fluid loss control, emulsion stability, lubricity, etc. Developing environment friendly chemicals to provide the above-mentioned drilling fluid properties is a significant step taken towards sustainability and reducing carbon footprint besides suitability for aquifers and offshore environments. Several fatty acid-based chemicals used in drilling fluids as fatty acids offer eco-friendly and bio-degradable properties besides required drilling fluid properties. Vegatable oil contains triglycerides which is a potential source of fatty acids and their derivatives. Waste vegetable oil (WVO) provides a perpetual and sustainable source of raw material for various types of eco-friendly additives development. Waste vegetable oil is subjected to simple chemical modification of base hydrolysis process and mixtures of fatty acids have been obtained after finishing a sequence of clean-up process of reaction mixture. The fatty acids obtained are environment-friendly, bio-degradable and non-toxic. Due to technical, economic and environmental advantages of products derived from waste vegetable oils, we have undertaken several research projects to produce various chemicals from waste vegetable oil for oil and gas field applications. Fatty acid-based products mainly used in drilling fluids as lubricants to reduce torque and drag for water-based mud. In case of oil-based mud systems, fatty acid derived products are used as emulsifiers, wetting agents and rheology modifiers. However, these products have been either mixture of fatty acids and their derivatives or only derivatives of fatty acids. In our study, we have used the mixture of fatty acids obtained from chemical conversion of WVO for applications as lubricant for water-based mud and emulsifier and rheology modifier for invert emulsion oil-based mud systems. In this paper, we described the chemicals process for converting waste vegetable oil to fatty acids by base hydrolysis reaction in the first section. Application of synthesized fatty acids for water-based and oil-based mud formulation as lubricants, emulsifiers and rheology modifiers have been discussed in the second part of the paper.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 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":"87396983","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}
Lionel Kallang Laing, Seiji Shirai, K. Rosli, Oluwole A. Talabi, Nurul Suhaila Mohammad Fawzi
Block X of offshore Sarawak consists of stacked and multi-layer reservoirs that produce gas, condensate and oil where the production is in-commingle from many wells. 47 surface PVT samples were taken and analyzed from every reservoir during the exploration and initial production periods. Despite the number of samples and a series of PVT studies had been conducted, fluid PVT and its reservoir modelling application remain an uncertainty for Block X. Therefore, a comprehensive 3-phase PVT study was conducted, and its improved results will be implemented in the upcoming simulation model to represent fluid interactions not only within each reservoir but also between different reservoirs that are produced in commingle. Firstly, a detailed quality check and validation were performed on every sample using a systematic process proposed in Paredes et al. (2014) to identify high-quality samples. These samples were ranked based on their Fluid Sample Quality index (FSQI), and the best samples were carried forward for further analysis. Initial PVT grouping analysis was performed by plotting observed saturation pressure, composition, CGR and other key variables versus depth for the selected samples. The existing PVT models and compositional characterization, which were reviewed and found to be satisfactory except for the matching quality of liquid saturation, were used to generate predicted profile trends using Compositional gradient experiments and compared to the data to define the PVT data that could be grouped together. Next, modelling and calibration of Equation of State (EOS) parameters to match the observed properties from lab experiments were performed for each PVT group using the best sample from each group as identified by its FQSI value. The results of the new PVT calibrations showed improvements over the existing models with the variance between the group PVT model and lab observations ranging from 0.1 -2.2% in saturation pressure and 0.5 – 17.8 % in CGR. This indicated that reasonable group PVT models had been obtained. Despite, uncertainty for one of the PVT groups remained high as its fluid needed to be adjusted due to a large inconsistency between the observed gas-oil-contact (GOC) and the observed saturation pressure even when its sample's FQSI was good. Finally, the new PVT models were validated with the existing dynamic simulation models by initializing them close to the original sampling conditions and applying a compositional gradient. Comparisons with previous models show improvements between 3 − 58% when compared to the sample and early production data. Significant uncertainty remains for the reservoir or PVT group where the fluid adjustment was performed due to its limited production for further calibration. In addition, improvements were not immediately reflected in the dynamic history match of the existing models because of the variation in separator conditions during field life and the uncertainty of wells’ zonal contributions fr
{"title":"Comprehensive PVT Data Review, Fluid Characterization and Grouping Study for Block X in Sarawak, Malaysia","authors":"Lionel Kallang Laing, Seiji Shirai, K. Rosli, Oluwole A. Talabi, Nurul Suhaila Mohammad Fawzi","doi":"10.4043/31417-ms","DOIUrl":"https://doi.org/10.4043/31417-ms","url":null,"abstract":"\u0000 Block X of offshore Sarawak consists of stacked and multi-layer reservoirs that produce gas, condensate and oil where the production is in-commingle from many wells. 47 surface PVT samples were taken and analyzed from every reservoir during the exploration and initial production periods. Despite the number of samples and a series of PVT studies had been conducted, fluid PVT and its reservoir modelling application remain an uncertainty for Block X. Therefore, a comprehensive 3-phase PVT study was conducted, and its improved results will be implemented in the upcoming simulation model to represent fluid interactions not only within each reservoir but also between different reservoirs that are produced in commingle.\u0000 Firstly, a detailed quality check and validation were performed on every sample using a systematic process proposed in Paredes et al. (2014) to identify high-quality samples. These samples were ranked based on their Fluid Sample Quality index (FSQI), and the best samples were carried forward for further analysis. Initial PVT grouping analysis was performed by plotting observed saturation pressure, composition, CGR and other key variables versus depth for the selected samples. The existing PVT models and compositional characterization, which were reviewed and found to be satisfactory except for the matching quality of liquid saturation, were used to generate predicted profile trends using Compositional gradient experiments and compared to the data to define the PVT data that could be grouped together.\u0000 Next, modelling and calibration of Equation of State (EOS) parameters to match the observed properties from lab experiments were performed for each PVT group using the best sample from each group as identified by its FQSI value. The results of the new PVT calibrations showed improvements over the existing models with the variance between the group PVT model and lab observations ranging from 0.1 -2.2% in saturation pressure and 0.5 – 17.8 % in CGR. This indicated that reasonable group PVT models had been obtained. Despite, uncertainty for one of the PVT groups remained high as its fluid needed to be adjusted due to a large inconsistency between the observed gas-oil-contact (GOC) and the observed saturation pressure even when its sample's FQSI was good.\u0000 Finally, the new PVT models were validated with the existing dynamic simulation models by initializing them close to the original sampling conditions and applying a compositional gradient. Comparisons with previous models show improvements between 3 − 58% when compared to the sample and early production data. Significant uncertainty remains for the reservoir or PVT group where the fluid adjustment was performed due to its limited production for further calibration. In addition, improvements were not immediately reflected in the dynamic history match of the existing models because of the variation in separator conditions during field life and the uncertainty of wells’ zonal contributions fr","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86171736","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}
Wubo Liu, Xiaofei Gao, Qingquan Li, Yi Guo, Lei Yu, Chao Wang, B. Chang, Fei Wang, Shuzhong Li, Y. Shim
Located in offshore South China, XJ oil field entered the mature development phase after more than 20 years of production, with the water cut of the field increasing to 93%. A new strategy was executed starting in 2018 that targeted the remaining oil column, which was being squeezed by a strong bottomwater. One of the biggest challenges was the high uncertainty of the oil/water contacts in the current reservoir state. After reviewing the technical and geological challenges encountered, we will describe the successful approach taken to optimize the remaining reserves recovery using innovative horizontal well placement strategies. Using a few case studies, we will illustrate how we executed this innovative well placement strategy. This includes landing the horizontal wells at the upper part of the reservoir with low incident angle, drilling the horizontal sections close to the top of target zones using a reservoir boundary detection tool, and using a continuous packer for the well completion to reduce the water cut. In addition, we will describe how the team evaluated and selected logging technologies in the planning phase for proper well placement. The two cases discussed in this paper are based on horizontal wells completed using the following new strategy: maintaining a long lateral section in the upper layer of a predefined target, following the undulating structure while mapping the thin sandstone, keeping the trajectory in the target zone, etc. To ensure that each horizontal well could meet the target productivity index planned, real-time data were used in reservoir modeling to determine the required lateral length of each horizonal well. With the purpose of controlling water cut and improving oil recovery in these laterals, a new completion assembly, including a perforated liner with special completion material that prevented water from entering the liners, were installed in selected intervals according the logging data interpretation. Several observations will be highlighted, including: Real-time logging data can effectively evaluate the reservoir properties and structural changes along the lateral Optimum well placement in the lateral section is critical for draining the remaining oil column An optimized completion design based on real-time reservoir evaluation. The performance of the wells drilled to date shows that the production increased from 1,000 to 3,000 BOPD with zero to very low water cut. A reversing production trend from a declining trend to a growth trend is recorded. The successful implementation of the new strategy and the application of fit-for-purpose technologies in mature oil fields lead to improved production and increased oil recovery.
{"title":"Enhancing Oil Recovery in a Brown Oilfield of Offshore South China","authors":"Wubo Liu, Xiaofei Gao, Qingquan Li, Yi Guo, Lei Yu, Chao Wang, B. Chang, Fei Wang, Shuzhong Li, Y. Shim","doi":"10.4043/31365-ms","DOIUrl":"https://doi.org/10.4043/31365-ms","url":null,"abstract":"\u0000 Located in offshore South China, XJ oil field entered the mature development phase after more than 20 years of production, with the water cut of the field increasing to 93%. A new strategy was executed starting in 2018 that targeted the remaining oil column, which was being squeezed by a strong bottomwater. One of the biggest challenges was the high uncertainty of the oil/water contacts in the current reservoir state. After reviewing the technical and geological challenges encountered, we will describe the successful approach taken to optimize the remaining reserves recovery using innovative horizontal well placement strategies.\u0000 Using a few case studies, we will illustrate how we executed this innovative well placement strategy. This includes landing the horizontal wells at the upper part of the reservoir with low incident angle, drilling the horizontal sections close to the top of target zones using a reservoir boundary detection tool, and using a continuous packer for the well completion to reduce the water cut. In addition, we will describe how the team evaluated and selected logging technologies in the planning phase for proper well placement.\u0000 The two cases discussed in this paper are based on horizontal wells completed using the following new strategy: maintaining a long lateral section in the upper layer of a predefined target, following the undulating structure while mapping the thin sandstone, keeping the trajectory in the target zone, etc. To ensure that each horizontal well could meet the target productivity index planned, real-time data were used in reservoir modeling to determine the required lateral length of each horizonal well. With the purpose of controlling water cut and improving oil recovery in these laterals, a new completion assembly, including a perforated liner with special completion material that prevented water from entering the liners, were installed in selected intervals according the logging data interpretation. Several observations will be highlighted, including:\u0000 Real-time logging data can effectively evaluate the reservoir properties and structural changes along the lateral Optimum well placement in the lateral section is critical for draining the remaining oil column An optimized completion design based on real-time reservoir evaluation.\u0000 The performance of the wells drilled to date shows that the production increased from 1,000 to 3,000 BOPD with zero to very low water cut. A reversing production trend from a declining trend to a growth trend is recorded. The successful implementation of the new strategy and the application of fit-for-purpose technologies in mature oil fields lead to improved production and increased oil recovery.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"423 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76632809","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}
Youngbin Shan, Yaoguang Wu, Minjun Qin, Dongming Liu, Bin Yao
Understanding interwell connectivity is crucial for EOR decision making. In 1990, K.N Wood et al proposed a method to evaluate the interwell Residual Oil using a reactive tracer and a non-partition tracer. A decade later in 2001 (Joseph Tang, 2001), Joseph Tang et al proposed a method to identify the single well near bore residual oil saturation by puff and huff approach in a single well carbonate reservoir. Today the interwell connectivity is still under research. The objective of this paper is to propose latest study to evaluate interwell connectivity through two or more partitioning tracers to estimate the breakthrough, pore volume, sweeping channel geometry, high permeability channel, residual oil saturation, etc Thanks to the new development in tracer technologies, today we can use two distinctive tracers to pump through injection well and collect tracers produced in all production wells. The different partition coefficients for two tracers can reveal the lag factor for the sweeping channel and further derive the statistical channel breakthrough time, pore volume, geometry, tortuosity and residual oil saturation. The theory, derivation and applications of the concepts are described in this paper. Based on the analysis, sweeping channels statistical information can be calculated by a simple mathematical expression of the ratio of two distinctive tracer mass produced from production wells, the ratio of two tracer dynamic partitioning coefficients and the ratio of two injected tracer mass. With this information, operator can investigate a compartmentalization in the field to optimize flooding plan. One 9-piont injection well grid were analyzed, and results are shown in this paper. Those results are important input to operators' reservoir model. It revealed the major sweeping channels and azimuths, the major residual oil channel and their azimuths, the possible tortuous channels and their azimuths which gives operator a direction of where the residual oil resides and how easy or difficult it can be recovered in tertiary oil production. This new theory analyzes sweeping channel statistical information from produced masses of two distinctively partitioning tracers, which follows a rigorous mathematical derivation and setup a volume factor equation relating to produced masses of two partitioning tracers. The partitioning coefficient is also modified by a dynamic factor to better simulate the moving partition in channel rather than the static partitioning between brine and oil.
了解井间连通性对于提高采收率决策至关重要。1990年，K.N Wood等人提出了一种利用活性示踪剂和非分割示踪剂评价井间剩余油的方法。十年后的2001年(Joseph Tang, 2001)， Joseph Tang等人提出了利用吞吐法识别单井碳酸盐岩储层近井剩余油饱和度的方法。目前，井间连通性仍在研究中。本文的目的是通过两种或两种以上的分区示踪剂来评估井间连通性，以估计突破、孔隙体积、扫描通道几何形状、高渗透通道、残余油饱和度等。由于示踪剂技术的新发展，今天我们可以使用两种不同的示踪剂来泵送注水井，并收集所有生产井的示踪剂。两种示踪剂的不同配分系数可以揭示波及通道的滞后系数，进而推导出统计通道突破时间、孔隙体积、几何形状、弯曲度和残余油饱和度。本文介绍了这些概念的理论、推导和应用。在此基础上，通过生产井两种不同示踪剂产量的比值、两种示踪剂动态分配系数的比值和两种注入示踪剂质量的比值的简单数学表达式，可以计算出扫描通道的统计信息。有了这些信息，作业者就可以研究油田的分区，以优化驱油计划。对某9点注水井网进行了分析，并给出了分析结果。这些结果是作业者油藏模型的重要输入。揭示了三次采油中剩余油的主要扫油通道及其方位、主要剩余油通道及其方位、可能的弯曲通道及其方位，为作业者判断剩余油的位置和开采难易程度提供了指导。该理论分析了两种不同分区示踪剂产质量的扫道统计信息，并进行了严格的数学推导，建立了与两种分区示踪剂产质量有关的体积因子方程。通过对配分系数进行动态修正，可以更好地模拟通道内的移动配分，而不是盐水和油之间的静态配分。
{"title":"Interwell Connectivity Study","authors":"Youngbin Shan, Yaoguang Wu, Minjun Qin, Dongming Liu, Bin Yao","doi":"10.4043/31624-ms","DOIUrl":"https://doi.org/10.4043/31624-ms","url":null,"abstract":"\u0000 Understanding interwell connectivity is crucial for EOR decision making.\u0000 In 1990, K.N Wood et al proposed a method to evaluate the interwell Residual Oil using a reactive tracer and a non-partition tracer. A decade later in 2001 (Joseph Tang, 2001), Joseph Tang et al proposed a method to identify the single well near bore residual oil saturation by puff and huff approach in a single well carbonate reservoir. Today the interwell connectivity is still under research.\u0000 The objective of this paper is to propose latest study to evaluate interwell connectivity through two or more partitioning tracers to estimate the breakthrough, pore volume, sweeping channel geometry, high permeability channel, residual oil saturation, etc\u0000 Thanks to the new development in tracer technologies, today we can use two distinctive tracers to pump through injection well and collect tracers produced in all production wells. The different partition coefficients for two tracers can reveal the lag factor for the sweeping channel and further derive the statistical channel breakthrough time, pore volume, geometry, tortuosity and residual oil saturation. The theory, derivation and applications of the concepts are described in this paper.\u0000 Based on the analysis, sweeping channels statistical information can be calculated by a simple mathematical expression of the ratio of two distinctive tracer mass produced from production wells, the ratio of two tracer dynamic partitioning coefficients and the ratio of two injected tracer mass. With this information, operator can investigate a compartmentalization in the field to optimize flooding plan.\u0000 One 9-piont injection well grid were analyzed, and results are shown in this paper. Those results are important input to operators' reservoir model. It revealed the major sweeping channels and azimuths, the major residual oil channel and their azimuths, the possible tortuous channels and their azimuths which gives operator a direction of where the residual oil resides and how easy or difficult it can be recovered in tertiary oil production.\u0000 This new theory analyzes sweeping channel statistical information from produced masses of two distinctively partitioning tracers, which follows a rigorous mathematical derivation and setup a volume factor equation relating to produced masses of two partitioning tracers. The partitioning coefficient is also modified by a dynamic factor to better simulate the moving partition in channel rather than the static partitioning between brine and oil.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82613731","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}
Ronald C. Siregar, Safuan Ramli, David Turner, Kachin Prachayarittikool, Mohammad Iffwad
The oil and gas fields offshore Malaysia-Thailand border are well known for the presence of high pressure and high temperature reservoir characteristics. The hot environment favours the use of hostile wireline logging tools over logging while drilling tools for some measurements. High overbalance conditions are sometimes a necessary requirement to safely drill particular formations but bring with them operational challenges. For wireline logging a critical hazard is that of becoming differentially stuck, especially in the case of stationary logs such as pressure measurements, sampling, and coring. A reduction in allowable safe stationary times for these measurements can also compromise the quality of the results. Production wells in this area are generally drilled with slim 6-1/8″ sections through the reservoir. As the borehole becomes smaller the risk of sticking increases as the tool contact area increases and so is a particular concern in slim holes. This often leads to logging being run using costly pipe conveyed methods or the inability to obtain required data altogether. This paper presents case histories of wireline formation pressure testing and sampling in 6-1/8″ sections with high deviation, 3D trajectory boreholes with overbalance pressures of over 2,000 psi. The use of a high-performance roller system to create tool stand-off to mitigate differential sticking as well as eliminate friction is described, along with the use of an engineered hole finder to address hole access concerns. The importance of wireline simulation models to identify risks and test solutions in such conditions is also considered. Slim hole logging and logging under overbalanced conditions are often a source of concern for subsurface, drilling and service company personnel alike. Describing a successful approach to address both is of interest to all involved parties and should provide ideas and confidence to plan cost-effective logging in similar wells.
{"title":"Mitigation of Slim Open Hole Wireline Logging Risk Under High Overbalance Conditions","authors":"Ronald C. Siregar, Safuan Ramli, David Turner, Kachin Prachayarittikool, Mohammad Iffwad","doi":"10.4043/31373-ms","DOIUrl":"https://doi.org/10.4043/31373-ms","url":null,"abstract":"\u0000 The oil and gas fields offshore Malaysia-Thailand border are well known for the presence of high pressure and high temperature reservoir characteristics. The hot environment favours the use of hostile wireline logging tools over logging while drilling tools for some measurements.\u0000 High overbalance conditions are sometimes a necessary requirement to safely drill particular formations but bring with them operational challenges. For wireline logging a critical hazard is that of becoming differentially stuck, especially in the case of stationary logs such as pressure measurements, sampling, and coring. A reduction in allowable safe stationary times for these measurements can also compromise the quality of the results.\u0000 Production wells in this area are generally drilled with slim 6-1/8″ sections through the reservoir. As the borehole becomes smaller the risk of sticking increases as the tool contact area increases and so is a particular concern in slim holes. This often leads to logging being run using costly pipe conveyed methods or the inability to obtain required data altogether.\u0000 This paper presents case histories of wireline formation pressure testing and sampling in 6-1/8″ sections with high deviation, 3D trajectory boreholes with overbalance pressures of over 2,000 psi. The use of a high-performance roller system to create tool stand-off to mitigate differential sticking as well as eliminate friction is described, along with the use of an engineered hole finder to address hole access concerns. The importance of wireline simulation models to identify risks and test solutions in such conditions is also considered.\u0000 Slim hole logging and logging under overbalanced conditions are often a source of concern for subsurface, drilling and service company personnel alike. Describing a successful approach to address both is of interest to all involved parties and should provide ideas and confidence to plan cost-effective logging in similar wells.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89701848","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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