Viscoelastic surfactant (VES) have been successfully applied as acid-diversion fluids. However, high temperature, interaction of VES and Fe(III), addition of alcohol-based additives, and chelating agents all interfere with the apparent viscosity of the VES-based acid and reduce its efficiency. In the present study, the interactions of Fe(III) with a new type of VES-based acid system, which can be applied effectively for diversion at high temperatures, were characterized. Viscosity measurements were conducted on the VES-based acid in the presence of different concentrations of Fe(III) to characterize the rheological properties of the VES-based acid. The results showed that addition of Fe(III) in the concentration range of 2000 to 10000 ppm, lead to increase in the viscosity of the VES-based acid even at room temperature. Higher concentration of Fe(III) (more than 40000 ppm) lead to phase separation of VES out of the acid and formation of a brown gel-like material, which is considered as the main cause of formation damage by VES-based diversion fluids. IR spectroscopy was employed to understand the nature of the VES interactions with Fe(III) in live acid conditions. Also, UV-vis spectroscopy was conducted to determine stoichiometry of the reaction as well. The results show that interaction of amide part of the VES with Fe(III) that results in screening the repulsion forces between surfactant head groups and formation of wormlike micelles is the primary reason for increase in the viscosity. To the best of authors' knowledge, although Formation damage caused by VES-based system due to iron contamination were reported previously both in the laboratory studies and field applications, the present paper is the first mechanistic attempt to characterize and understand the nature of a VES-based system interaction with Fe(III) as the driving force for the occurrence of reported formation damage. The findings of the present study can be utilized to further investigation of the effects of additives on the performance of VES-based systems.
{"title":"Characterization of Iron Interaction with Viscoelastic Surfactant VES-Based Stimulation Fluid","authors":"S. Afra, H. Samouei, H. Nasr-El-Din","doi":"10.2118/194862-MS","DOIUrl":"https://doi.org/10.2118/194862-MS","url":null,"abstract":"\u0000 Viscoelastic surfactant (VES) have been successfully applied as acid-diversion fluids. However, high temperature, interaction of VES and Fe(III), addition of alcohol-based additives, and chelating agents all interfere with the apparent viscosity of the VES-based acid and reduce its efficiency. In the present study, the interactions of Fe(III) with a new type of VES-based acid system, which can be applied effectively for diversion at high temperatures, were characterized.\u0000 Viscosity measurements were conducted on the VES-based acid in the presence of different concentrations of Fe(III) to characterize the rheological properties of the VES-based acid. The results showed that addition of Fe(III) in the concentration range of 2000 to 10000 ppm, lead to increase in the viscosity of the VES-based acid even at room temperature. Higher concentration of Fe(III) (more than 40000 ppm) lead to phase separation of VES out of the acid and formation of a brown gel-like material, which is considered as the main cause of formation damage by VES-based diversion fluids. IR spectroscopy was employed to understand the nature of the VES interactions with Fe(III) in live acid conditions. Also, UV-vis spectroscopy was conducted to determine stoichiometry of the reaction as well. The results show that interaction of amide part of the VES with Fe(III) that results in screening the repulsion forces between surfactant head groups and formation of wormlike micelles is the primary reason for increase in the viscosity.\u0000 To the best of authors' knowledge, although Formation damage caused by VES-based system due to iron contamination were reported previously both in the laboratory studies and field applications, the present paper is the first mechanistic attempt to characterize and understand the nature of a VES-based system interaction with Fe(III) as the driving force for the occurrence of reported formation damage. The findings of the present study can be utilized to further investigation of the effects of additives on the performance of VES-based systems.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75007911","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}
H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, R. Flori, M. Alsaba, A. Amer
Oil/gas exploration, drilling, production, and reservoir management are challenging these days since most oil and gas conventional sources are already discovered and have been producing for many years. That is why petroleum engineers are trying to use advanced tools such as artificial neural networks (ANNs) to help to make the decision to reduce non-productive time and cost. A good number of papers about the applications of ANNs in the petroleum literature were reviewed and summarized in tables. The applications were classified into four groups; applications of ANNs in explorations, drilling, production, and reservoir engineering. A good number of applications in the literature of petroleum engineering were tabulated. Also, a formalized methodology to apply the ANNs for any petroleum application was presented and accomplished by a flowchart that can serve as a practical reference to apply the ANNs for any petroleum application. The method was broken down into steps that can be followed easily. The availability of huge data sets in the petroleum industry gives the opportunity to use these data to make better decisions and predict future outcomes. This paper will provide a review of applications of ANNs in petroleum engineering as well as a clear methodology on how to apply the ANNs for any petroleum application.
{"title":"Applications of Artificial Neural Networks in the Petroleum Industry: A Review","authors":"H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, R. Flori, M. Alsaba, A. Amer","doi":"10.2118/195072-MS","DOIUrl":"https://doi.org/10.2118/195072-MS","url":null,"abstract":"\u0000 Oil/gas exploration, drilling, production, and reservoir management are challenging these days since most oil and gas conventional sources are already discovered and have been producing for many years. That is why petroleum engineers are trying to use advanced tools such as artificial neural networks (ANNs) to help to make the decision to reduce non-productive time and cost.\u0000 A good number of papers about the applications of ANNs in the petroleum literature were reviewed and summarized in tables. The applications were classified into four groups; applications of ANNs in explorations, drilling, production, and reservoir engineering. A good number of applications in the literature of petroleum engineering were tabulated. Also, a formalized methodology to apply the ANNs for any petroleum application was presented and accomplished by a flowchart that can serve as a practical reference to apply the ANNs for any petroleum application. The method was broken down into steps that can be followed easily. The availability of huge data sets in the petroleum industry gives the opportunity to use these data to make better decisions and predict future outcomes. This paper will provide a review of applications of ANNs in petroleum engineering as well as a clear methodology on how to apply the ANNs for any petroleum application.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75403625","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}
H. Ayyad, Bashaiyer Dashti, A. Al-Nabhan, A. Al-Ajmi, B. Khan, K. Sassi, Lin Liang, G. Nagaraj
In Umm Niqa field, Lower Fars (LF) is a shallow, unconsolidated, sour heavy oil and low-pressure sand reservoir. During the current appraisal and exploratory phases, oil production forecasts based on reservoir simulation models were observed to be significantly higher than actual production. Furthermore, unexpected early water breakthrough and the rapid increase in the water cut added more complexity to the reservoir production. This paper will focus on how these challenges were addressed with a unique workflow. If the reservoir is producing more than one phase, then relative permeability determination becomes essential for the production forecast as well as production optimization to delay the water breakthrough. Due to the unconsolidated nature of LF reservoir, it was challenging to perform coring operation in this environment. In the few cases where cores were obtained, it was almost impossible to perform the relative permeability analysis on the core plugs. Therefore, there was a need to obtain this information by exploring other technique or methodology. Hence in-situ relative permeability technique was implemented in three different wells. To address the relative permeability determination challenge, an innovative approach was implemented in three different wells. This approach determines the relative permeability at downhole conditions by utilizing the fluids clean-up and sampling data during the wireline downhole formation testing as well as some advanced petrophysical measurements such as the array resistivity, the nuclear magnetic resonance (NMR), and the dielectric dispersion. The data obtained were used as inputs for a multi-physics integrated workflow, which inverts for the relative permeability curves based on the modified Brooks-Corey model. In this paper, it will be demonstrated how the relative permeability results obtained from this technique in these three wells were applied to update the reservoir simulation models. The production forecasts were found to be significantly improved and close to the actual production figures. The early water breakthrough is better anticipated; therefore, the production rate can be adjusted to delay it and maximize the oil recovery. This method provides an alternative and efficient way to derive the relative permeability curves when it is challenging to obtain from the conventional core analysis techniques. This helped to better understand the number of wells required to be drilled to achieve the planned production target. This paper adds to the literature unique case studies where relative permeability determination is required, however, not possible to be obtained through conventional industry techniques such as core analysis due to a highly unconsolidated formation. Hence, an innovative workflow was adopted to measure the relative permeability at downhole conditions.
在Umm Niqa油田，Lower Fars (LF)是一个浅层、松散、含硫稠油和低压砂岩油藏。在目前的评价和勘探阶段，根据油藏模拟模型预测的产油量明显高于实际产量。此外，早期突水和含水率的快速增加增加了油藏生产的复杂性。本文将重点讨论如何使用一个独特的工作流来解决这些挑战。如果储层正在生产多个相，那么相对渗透率的确定对于产量预测以及生产优化以延迟水突破至关重要。由于LF储层的松散性，在这种环境下进行取心作业具有挑战性。在获得岩心的少数情况下，几乎不可能对岩心塞进行相对渗透率分析。因此，有必要通过探索其他技术或方法来获得这些信息。因此，在3口不同的井中实施了原位相对渗透率技术。为了解决相对渗透率测定的难题，在三口不同的井中实施了一种创新的方法。该方法通过利用井下电缆地层测试期间的流体清理和采样数据，以及一些先进的岩石物理测量，如阵列电阻率、核磁共振(NMR)和介电色散，来确定井下条件下的相对渗透率。获得的数据被用作多物理场集成工作流的输入，该工作流基于改进的Brooks-Corey模型反演相对渗透率曲线。在本文中，将演示如何应用该技术在这三口井中获得的相对渗透率结果来更新油藏模拟模型。我们发现，产量预测有了显著改善，接近实际产量数字。较好地预测了早期突水;因此，可以调整产量来延迟生产，并最大限度地提高石油采收率。在常规岩心分析技术难以获得相对渗透率曲线的情况下，该方法提供了另一种有效的方法。这有助于更好地了解为实现计划生产目标所需钻的井数。本文为相关文献增加了独特的案例研究，这些案例需要确定相对渗透率，但由于地层高度松散，无法通过传统的工业技术(如岩心分析)获得。因此，采用了一种创新的工作流程来测量井下条件下的相对渗透率。
{"title":"Production Forecast and Optimization Utilizing In-Situ Determined Relative Permeability in a Highly Unconsolidated Sour Heavy Oil Clastic Reservoir","authors":"H. Ayyad, Bashaiyer Dashti, A. Al-Nabhan, A. Al-Ajmi, B. Khan, K. Sassi, Lin Liang, G. Nagaraj","doi":"10.2118/194923-MS","DOIUrl":"https://doi.org/10.2118/194923-MS","url":null,"abstract":"\u0000 In Umm Niqa field, Lower Fars (LF) is a shallow, unconsolidated, sour heavy oil and low-pressure sand reservoir. During the current appraisal and exploratory phases, oil production forecasts based on reservoir simulation models were observed to be significantly higher than actual production. Furthermore, unexpected early water breakthrough and the rapid increase in the water cut added more complexity to the reservoir production. This paper will focus on how these challenges were addressed with a unique workflow.\u0000 If the reservoir is producing more than one phase, then relative permeability determination becomes essential for the production forecast as well as production optimization to delay the water breakthrough. Due to the unconsolidated nature of LF reservoir, it was challenging to perform coring operation in this environment. In the few cases where cores were obtained, it was almost impossible to perform the relative permeability analysis on the core plugs. Therefore, there was a need to obtain this information by exploring other technique or methodology. Hence in-situ relative permeability technique was implemented in three different wells.\u0000 To address the relative permeability determination challenge, an innovative approach was implemented in three different wells. This approach determines the relative permeability at downhole conditions by utilizing the fluids clean-up and sampling data during the wireline downhole formation testing as well as some advanced petrophysical measurements such as the array resistivity, the nuclear magnetic resonance (NMR), and the dielectric dispersion. The data obtained were used as inputs for a multi-physics integrated workflow, which inverts for the relative permeability curves based on the modified Brooks-Corey model.\u0000 In this paper, it will be demonstrated how the relative permeability results obtained from this technique in these three wells were applied to update the reservoir simulation models. The production forecasts were found to be significantly improved and close to the actual production figures. The early water breakthrough is better anticipated; therefore, the production rate can be adjusted to delay it and maximize the oil recovery. This method provides an alternative and efficient way to derive the relative permeability curves when it is challenging to obtain from the conventional core analysis techniques. This helped to better understand the number of wells required to be drilled to achieve the planned production target.\u0000 This paper adds to the literature unique case studies where relative permeability determination is required, however, not possible to be obtained through conventional industry techniques such as core analysis due to a highly unconsolidated formation. Hence, an innovative workflow was adopted to measure the relative permeability at downhole conditions.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75608424","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}
Directional drillers have faced numerous challenges due to the right and left BHA walk tendencies. Walk, build, and drop tendencies increase sliding time thus reducing ROP and increasing CPF. Drilling tortuous wellbores are more prone to NPT, increased torque and downhole drag. It was noted that bit side forces and the tilt angle influence the DLS of the wellbore. In this study, novel predictive analytic models were developed to understand the factors that influence BHA assembly walk tendency as well as uncover the hidden relationships between several different features influencing the walk tendencies. Sixty-eight wells are included in this study with an initial model training and testing being executed on eight wells. A blind test was later performed on 57 wells with 149 different BHAs. The model accounted for the number and locations of the various components in the BHA and their different types. The modified BHAs are assumed to be a continuous beam supported by PDC bits, PDM, stabilizers, and an assembly, mirroring the contact points of the BHAs, and the wellbore. For simplification purposes, the assembly assumes that all three components are made of non-magnetic material with comparable OD, linear weight, and material. The assembly was based on the fact that these components had the same bending stiffness due to similar material and thus elasticity. Seven different ML models were experimented with to determine the lowest MAE. They included Gradient Boosting Machine, Random Forest, Artificial Neural Networks, and Adaboost. The attributes included mud density and formation type. Bit variables were composed of: OD, gauge length, length of inner and outer profile, TFA, manufacture, cutter size, and blade count. For PDM: location, OD, LW, length, bit to bend distance, and bend angle. The stabilizer included location, blade count, gauge length, gauge OD, LW, and stabilizer to bit depth and assembly specifications. Moreover, hole size, block height, hookload, WOB, ROP, differential pressure, mud flow rate, SPP, GR, Annular pressure loss, MSE, ECD at Bit, Bit RPM, Bit TOR, and bit aggressivity. The survey data had MD, Inclination, azimuth, and finally DLS. The models showed that the side forces in the form of seven dominant factors were the main culprits in influencing the walk direction of the drill bit. There was a highly significant relationship with a MAE of 14.7% between stabilizer location, gauge OD, PDM bit to bend distance, bit gauge, PDM differential pressure, ROP, WOB, inclination, and Hookload. These results prove to be a great advantage in controlling the drilling direction and reaching the target zone in minimal time. The optimized machine learning model helped optimize rotatory drilling time, ROP, smoother wellbores, and Lower CPF overall.
{"title":"Using Supervised Machine Learning Algorithms to Predict BHA Walk Tendencies","authors":"C. Noshi","doi":"10.2118/195111-MS","DOIUrl":"https://doi.org/10.2118/195111-MS","url":null,"abstract":"\u0000 Directional drillers have faced numerous challenges due to the right and left BHA walk tendencies. Walk, build, and drop tendencies increase sliding time thus reducing ROP and increasing CPF. Drilling tortuous wellbores are more prone to NPT, increased torque and downhole drag. It was noted that bit side forces and the tilt angle influence the DLS of the wellbore. In this study, novel predictive analytic models were developed to understand the factors that influence BHA assembly walk tendency as well as uncover the hidden relationships between several different features influencing the walk tendencies. Sixty-eight wells are included in this study with an initial model training and testing being executed on eight wells. A blind test was later performed on 57 wells with 149 different BHAs. The model accounted for the number and locations of the various components in the BHA and their different types. The modified BHAs are assumed to be a continuous beam supported by PDC bits, PDM, stabilizers, and an assembly, mirroring the contact points of the BHAs, and the wellbore. For simplification purposes, the assembly assumes that all three components are made of non-magnetic material with comparable OD, linear weight, and material. The assembly was based on the fact that these components had the same bending stiffness due to similar material and thus elasticity.\u0000 Seven different ML models were experimented with to determine the lowest MAE. They included Gradient Boosting Machine, Random Forest, Artificial Neural Networks, and Adaboost. The attributes included mud density and formation type. Bit variables were composed of: OD, gauge length, length of inner and outer profile, TFA, manufacture, cutter size, and blade count. For PDM: location, OD, LW, length, bit to bend distance, and bend angle. The stabilizer included location, blade count, gauge length, gauge OD, LW, and stabilizer to bit depth and assembly specifications. Moreover, hole size, block height, hookload, WOB, ROP, differential pressure, mud flow rate, SPP, GR, Annular pressure loss, MSE, ECD at Bit, Bit RPM, Bit TOR, and bit aggressivity. The survey data had MD, Inclination, azimuth, and finally DLS.\u0000 The models showed that the side forces in the form of seven dominant factors were the main culprits in influencing the walk direction of the drill bit. There was a highly significant relationship with a MAE of 14.7% between stabilizer location, gauge OD, PDM bit to bend distance, bit gauge, PDM differential pressure, ROP, WOB, inclination, and Hookload.\u0000 These results prove to be a great advantage in controlling the drilling direction and reaching the target zone in minimal time. The optimized machine learning model helped optimize rotatory drilling time, ROP, smoother wellbores, and Lower CPF overall.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82136797","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. Amer, M. Al-Wadi, Hanan Salem, A. Sajer, M. Al-Hajeri, A. Najem
Outcrop work represents the main source of analogs used to model subsurface reservoirs. Without such explanation of reservoir geometry, architecture, and characterization, producing subsurface formations would be largely uncertain. The aim of this paper is to build a geological static model for the Enjefa Beach outcrop exposed in Kuwait and use it to better understand subsurface reservoir architectures. This was achieved by acquiring several traverses along the outcrop, describing the various rock units, and understanding the depositional facies and facies associations. The next stage was to model each depositional unit as a separate zone embedded in an integrated model. This was followed by developing a forward synthetic three-dimensional seismic model to better understand how such reservoir architecture may appear in the subsurface. The final step was to use these findings in modeling a subsurface Cretaceous reservoir in northeastern Kuwait. The resultant model demonstrated that detailed geological complexities can be captured by conventional modeling techniques; in the model, the middle shoreface, upper shoreface, foreshore, and tidal channel complexes were statically modeled. Subsurface seismic data showed a series of highly sinuous meandering channels. Stacking patterns were found to vary among vertical, climbing, and compensational stacking patterns.
{"title":"Geological Modelling of the Enjefa Beach Marginal Marine Outcrop; A Comparison Between Holocene and Cretaceous Tidal Channel Complexes","authors":"A. Amer, M. Al-Wadi, Hanan Salem, A. Sajer, M. Al-Hajeri, A. Najem","doi":"10.2118/194895-MS","DOIUrl":"https://doi.org/10.2118/194895-MS","url":null,"abstract":"\u0000 Outcrop work represents the main source of analogs used to model subsurface reservoirs. Without such explanation of reservoir geometry, architecture, and characterization, producing subsurface formations would be largely uncertain. The aim of this paper is to build a geological static model for the Enjefa Beach outcrop exposed in Kuwait and use it to better understand subsurface reservoir architectures. This was achieved by acquiring several traverses along the outcrop, describing the various rock units, and understanding the depositional facies and facies associations. The next stage was to model each depositional unit as a separate zone embedded in an integrated model. This was followed by developing a forward synthetic three-dimensional seismic model to better understand how such reservoir architecture may appear in the subsurface. The final step was to use these findings in modeling a subsurface Cretaceous reservoir in northeastern Kuwait. The resultant model demonstrated that detailed geological complexities can be captured by conventional modeling techniques; in the model, the middle shoreface, upper shoreface, foreshore, and tidal channel complexes were statically modeled. Subsurface seismic data showed a series of highly sinuous meandering channels. Stacking patterns were found to vary among vertical, climbing, and compensational stacking patterns.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79842461","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}
Through Tubing Mechanical Shut off Process using electric line has been an economical and successful way to isolate undesired perforated intervals in cased whole completions. During the late 1980s & early 1990s the technology became more reliable so the oil & gas industry began to put more trust in eline capabilities for the through tubing shut-offs. Many of offshore operating companies including Gulf Of Suez Petroleum Company "GUPCO" adopted the technique in order to minimize the number of rig work overs and accelerate add rate activities using rigless units. TTBP has proved very reliable in most of the cases however; the success rate has been debatable for highly deviated wells with high-pressure differential across the plug. Eline applications normally struggle at deviations > 60°, because of losing the gravity force driving the tools downward, limitations of tool string length due to dogleg in the angle build up sections. Several through tubing options are now available to overcome these challenges, for example coiled tubing, which requires rig assist for offshore sattelites application, & eline tractoring, which adds more cost to eline job and depends on local availability in the area of operation. TT mechanical shut offs face some challenges more than ability to deploy tools to required depth. Several types of through tubing cement dump bailers are available in the market; however not many jobs were performed in deviations > 70°, there is always a debate about capability of bailer to dump all cement on depth at such deviation where gravity force is minimal. In addition, the effect of cement slumping in higher deviations is another challenge for building a good cement sheeth that guarantees good sheer bond strength and able to withstand required pressure differential. A Challenging example was an offshore horizontal well where the primary target is required to be isolated and the objective is to test a new reservoir in the field which was not tested before in the area. Due to uncertainity in productivity, saturation & fluid type "Oil or gas" of the new characterized reservoir. The operations was intended to be at the minimum possible cost in order to keep the business risk at the lowest level. The target perforation interval was located in the build section of the horizontal well where deviation angle is 74-76 degrees. The existing perforations were flooded out and it was necessary to isolate prior to test of the target reservoir. Isolation using through tubing bridge plug on eline was assessed and different operation risks were evaluated, conveyence to the target depth without an eline tractor was assessed in the planning phase using a tension model. Slickline operation was modified to confirm the validity of the model and we successfully reached the target depth using slickline. During the planning phase, we considered many precautions to guarantee job success. A successful mechanical shut off job in a deviation of 74-76 degree was
{"title":"Successful Application of through Tubing Mechanical Shut Off Technique in a Deviation More than 70°","authors":"M. Koriesh, A. Basyouni, M. Vazquez","doi":"10.2118/194864-MS","DOIUrl":"https://doi.org/10.2118/194864-MS","url":null,"abstract":"\u0000 Through Tubing Mechanical Shut off Process using electric line has been an economical and successful way to isolate undesired perforated intervals in cased whole completions. During the late 1980s & early 1990s the technology became more reliable so the oil & gas industry began to put more trust in eline capabilities for the through tubing shut-offs.\u0000 Many of offshore operating companies including Gulf Of Suez Petroleum Company \"GUPCO\" adopted the technique in order to minimize the number of rig work overs and accelerate add rate activities using rigless units. TTBP has proved very reliable in most of the cases however; the success rate has been debatable for highly deviated wells with high-pressure differential across the plug.\u0000 Eline applications normally struggle at deviations > 60°, because of losing the gravity force driving the tools downward, limitations of tool string length due to dogleg in the angle build up sections. Several through tubing options are now available to overcome these challenges, for example coiled tubing, which requires rig assist for offshore sattelites application, & eline tractoring, which adds more cost to eline job and depends on local availability in the area of operation. TT mechanical shut offs face some challenges more than ability to deploy tools to required depth. Several types of through tubing cement dump bailers are available in the market; however not many jobs were performed in deviations > 70°, there is always a debate about capability of bailer to dump all cement on depth at such deviation where gravity force is minimal. In addition, the effect of cement slumping in higher deviations is another challenge for building a good cement sheeth that guarantees good sheer bond strength and able to withstand required pressure differential.\u0000 A Challenging example was an offshore horizontal well where the primary target is required to be isolated and the objective is to test a new reservoir in the field which was not tested before in the area. Due to uncertainity in productivity, saturation & fluid type \"Oil or gas\" of the new characterized reservoir. The operations was intended to be at the minimum possible cost in order to keep the business risk at the lowest level. The target perforation interval was located in the build section of the horizontal well where deviation angle is 74-76 degrees.\u0000 The existing perforations were flooded out and it was necessary to isolate prior to test of the target reservoir. Isolation using through tubing bridge plug on eline was assessed and different operation risks were evaluated, conveyence to the target depth without an eline tractor was assessed in the planning phase using a tension model. Slickline operation was modified to confirm the validity of the model and we successfully reached the target depth using slickline. During the planning phase, we considered many precautions to guarantee job success.\u0000 A successful mechanical shut off job in a deviation of 74-76 degree was ","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81840978","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}
One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it. The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery. Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy. Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
{"title":"New Development Concept Lead to Five Folds Recovery Increase in a North Kuwait Field","authors":"A. Daoud, B. Al-Otaibi, Dhuha Alkandari","doi":"10.2118/195084-MS","DOIUrl":"https://doi.org/10.2118/195084-MS","url":null,"abstract":"\u0000 One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.\u0000 The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.\u0000 Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.\u0000 Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81198442","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}
L. Lawal, M. Mahmoud, A. Adebayo, Rizwan Husain Syed
Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements. Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix. Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.
{"title":"A Novel Method to Determine Kerogen Content of Tight Gas Shale","authors":"L. Lawal, M. Mahmoud, A. Adebayo, Rizwan Husain Syed","doi":"10.2118/194808-MS","DOIUrl":"https://doi.org/10.2118/194808-MS","url":null,"abstract":"\u0000 Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements.\u0000 Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix.\u0000 Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77832461","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}
M. Altammar, Tariq Almubarak, Hicham El-Hajj, W. Suzart, Ibrahim Al-Hulail
An unconventional clay-control substitute was introduced in the Middle East and North Africa (MENA) region, where a total of twenty-nine wells have been completed successfully. This paper presents a homogenous, on-the-fly clay stabilizer, which renders clay insensitive to fresh water, preventing swelling and migration while leaving formation/fluid properties unchanged. Formation damage and drilling difficulties are very commonly associated with clay problems. Clay-control additives are crucial in any drilling operation, particularly in Saudi Arabian gas wells where drilling activities use underbalanced coiled tubing drilling (UBCTD). UBCTD optimizes this on-the-fly alternative and achieves multiple objectives. The primary objective of UBCTD is to minimize fresh water contact time with the formation through flowing back; however, having to change the bottom hole assembly (BHA) because of wear halts circulation and production and increases fresh water contact with the formation, which could lead to clay swelling in the near wellbore area and result in damage. This new fluid system has proven to provide superior protection even at higher rates of penetration. In addition, inorganic compound quality and inconsistency could lead to deposits on equipment and affect instrumentation performance with UBCTD at the production/treatment systems when flowing back while drilling. These issues can be avoided with this treatment, and the costs associated with equipment rental can be reduced. Additionally, concentrations can be changed on-the-fly as needed depending on the formation. This clay stabilization fluid helps control clay swelling, fines migration, and decreases hydrostatic pressure and friction pressure when exposed to a freshwater-based fluid system. It fundamentally adheres to the clay mineral surface and prevents ion exchange, therefore providing pore throat protection and deterring damage to the formation matrix. The treatment was used during underbalanced drilling projects where each well/project had two to three laterals of low permeability. It was successfully used in nine pilot projects with excellent results, awarding distinctive advantages compared to typically used inorganic-based clay and shale stabilizers This development could increase the efficiency of downhole motors and drill bits as a result of low friction pressure and minimal deposits left behind. No additional equipment or manpower is necessary compared to other inorganic compound treatments. In addition, it reduces mixing time (on-the-fly) and is added at a lower concentration, which helps reduce logistical challenges and makes the treatment more efficient at a lower cost and with a reduced footprint. Original permeability is not affected by the addition of this fluid system, and permanent clay stabilization is provided. Data are presented and cross-checked with adjacent wells/candidates that used conventional clay protection such as inorganic compounds. Gamma-ray logs, th
{"title":"Unconventional Clay Control Alternative to Inorganic Compounds that Can Prevent Swelling and Reduce Friction in Underbalanced Drilling","authors":"M. Altammar, Tariq Almubarak, Hicham El-Hajj, W. Suzart, Ibrahim Al-Hulail","doi":"10.2118/194869-MS","DOIUrl":"https://doi.org/10.2118/194869-MS","url":null,"abstract":"An unconventional clay-control substitute was introduced in the Middle East and North Africa (MENA) region, where a total of twenty-nine wells have been completed successfully. This paper presents a homogenous, on-the-fly clay stabilizer, which renders clay insensitive to fresh water, preventing swelling and migration while leaving formation/fluid properties unchanged. Formation damage and drilling difficulties are very commonly associated with clay problems. Clay-control additives are crucial in any drilling operation, particularly in Saudi Arabian gas wells where drilling activities use underbalanced coiled tubing drilling (UBCTD). UBCTD optimizes this on-the-fly alternative and achieves multiple objectives. The primary objective of UBCTD is to minimize fresh water contact time with the formation through flowing back; however, having to change the bottom hole assembly (BHA) because of wear halts circulation and production and increases fresh water contact with the formation, which could lead to clay swelling in the near wellbore area and result in damage. This new fluid system has proven to provide superior protection even at higher rates of penetration. In addition, inorganic compound quality and inconsistency could lead to deposits on equipment and affect instrumentation performance with UBCTD at the production/treatment systems when flowing back while drilling. These issues can be avoided with this treatment, and the costs associated with equipment rental can be reduced. Additionally, concentrations can be changed on-the-fly as needed depending on the formation. This clay stabilization fluid helps control clay swelling, fines migration, and decreases hydrostatic pressure and friction pressure when exposed to a freshwater-based fluid system. It fundamentally adheres to the clay mineral surface and prevents ion exchange, therefore providing pore throat protection and deterring damage to the formation matrix. The treatment was used during underbalanced drilling projects where each well/project had two to three laterals of low permeability. It was successfully used in nine pilot projects with excellent results, awarding distinctive advantages compared to typically used inorganic-based clay and shale stabilizers This development could increase the efficiency of downhole motors and drill bits as a result of low friction pressure and minimal deposits left behind. No additional equipment or manpower is necessary compared to other inorganic compound treatments. In addition, it reduces mixing time (on-the-fly) and is added at a lower concentration, which helps reduce logistical challenges and makes the treatment more efficient at a lower cost and with a reduced footprint. Original permeability is not affected by the addition of this fluid system, and permanent clay stabilization is provided. Data are presented and cross-checked with adjacent wells/candidates that used conventional clay protection such as inorganic compounds. Gamma-ray logs, th","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78730565","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}
Muhammad A. Siddiqui, S. Tariq, J. Haneef, S. Ali, A. Manzoor
Asphaltene deposition can cause production reduction in oil fields and can create problems in surface/subsurface equipment. The three main factors which affect asphaltene stability in a crude oil are the changes in pressure, temperature and composition. Composition changes occur as the pressure depletes with time and fluid becomes heavier or with gas or chemical injection in reservoir. Any of these changes can destabilizes the asphaltene in crude oil and can cause different operational difficulties, loss in production and increases safety concerns. The objective of this study is to develop a workflow for modeling asphaltene precipitation during pressure depletion and its application to develop mitigation strategy via asphaltene stability maps for a gas condensate field in South Potwar basin, Pakistan
{"title":"Asphaltene Stability Analysis for Crude Oils and Their Relationship With Asphaltene Precipitation Models for a Gas Condensate Field","authors":"Muhammad A. Siddiqui, S. Tariq, J. Haneef, S. Ali, A. Manzoor","doi":"10.2118/194706-MS","DOIUrl":"https://doi.org/10.2118/194706-MS","url":null,"abstract":"\u0000 Asphaltene deposition can cause production reduction in oil fields and can create problems in surface/subsurface equipment. The three main factors which affect asphaltene stability in a crude oil are the changes in pressure, temperature and composition. Composition changes occur as the pressure depletes with time and fluid becomes heavier or with gas or chemical injection in reservoir. Any of these changes can destabilizes the asphaltene in crude oil and can cause different operational difficulties, loss in production and increases safety concerns. The objective of this study is to develop a workflow for modeling asphaltene precipitation during pressure depletion and its application to develop mitigation strategy via asphaltene stability maps for a gas condensate field in South Potwar basin, Pakistan","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90482807","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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