In early 2016, oil price has fallen to its lowest level (30.32 US$/bbl) over the last 12 years. Since then, petroleum exploration and exploitation activities are decreasing worldwide due to high production cost and low oil prices. As of December 2017, there were 435 projects approved by the government of Indonesia, which is expected to maintain the national energy supply and to increase national income from oil and gas industry. This paper will evaluate and analyze the oil and gas reserves per project to help Contractors to find the area in Indonesia that has the highest trend of oil and gas reserves per project so that they can produce big revenue. The purpose of this paper is, to divide the geographical areas of Indonesia into 5 different areas (Sumatera, Java, Kalimantan, Sulawesi and Papua). Then, to collect the data that related to projects and oil and gas discoveries and the trend of oil and gas discoveries per project are calculated and analyzed by using the creaming curve method, the result will be distributed to those aforementioned areas and finally define the area that has the highest and the lowest number (trend) of oil and gas discoveries per project. Based on the analysis of 435 Projects in Indonesia, Sulawesi is estimated to have the highest amount of oil and gas reserves by 111.24 MMBOE per project which means that these areas become the most interesting area for Contractors to produce profitable projects, meanwhile Sumatera is estimated to have the lowest amount of oil and gas reserves by 7.19 MMBOE per project which means that these areas are becoming the most mature area in Indonesia. Finally, this paper is expected to provide contractors a quick look at oil and gas industry in Indonesia especially the contractors who are looking for the giant oil and gas reserves and also help them create their petroleum exploration and exploitation strategy in Indonesia by considering on this information which will provide benefits for both government and contractor.
{"title":"Forecasting and Modelling the Oil and Gas Reserves in Indonesia Using the Creaming Curve and Linear Regression Analysis","authors":"A. Azizurrofi, Rikky Rahmat Firdaus","doi":"10.2118/194786-MS","DOIUrl":"https://doi.org/10.2118/194786-MS","url":null,"abstract":"\u0000 In early 2016, oil price has fallen to its lowest level (30.32 US$/bbl) over the last 12 years. Since then, petroleum exploration and exploitation activities are decreasing worldwide due to high production cost and low oil prices.\u0000 As of December 2017, there were 435 projects approved by the government of Indonesia, which is expected to maintain the national energy supply and to increase national income from oil and gas industry. This paper will evaluate and analyze the oil and gas reserves per project to help Contractors to find the area in Indonesia that has the highest trend of oil and gas reserves per project so that they can produce big revenue.\u0000 The purpose of this paper is, to divide the geographical areas of Indonesia into 5 different areas (Sumatera, Java, Kalimantan, Sulawesi and Papua). Then, to collect the data that related to projects and oil and gas discoveries and the trend of oil and gas discoveries per project are calculated and analyzed by using the creaming curve method, the result will be distributed to those aforementioned areas and finally define the area that has the highest and the lowest number (trend) of oil and gas discoveries per project.\u0000 Based on the analysis of 435 Projects in Indonesia, Sulawesi is estimated to have the highest amount of oil and gas reserves by 111.24 MMBOE per project which means that these areas become the most interesting area for Contractors to produce profitable projects, meanwhile Sumatera is estimated to have the lowest amount of oil and gas reserves by 7.19 MMBOE per project which means that these areas are becoming the most mature area in Indonesia.\u0000 Finally, this paper is expected to provide contractors a quick look at oil and gas industry in Indonesia especially the contractors who are looking for the giant oil and gas reserves and also help them create their petroleum exploration and exploitation strategy in Indonesia by considering on this information which will provide benefits for both government and contractor.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"135 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89209440","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. Al-Muftah, Yusuf Buali, A. Mahmoud, Hamed AlGhadhban
The Bahrain Field, being the first oil discovery in the gulf region in 1932, is now in a mature stage of development. Crestal gas injection in the Mauddud reservoir has continued to be the strongest driving mechanism since 1938. Over the last five years, gas injection and fluid production rates have grown three folds with expanded drilling, workovers, and high volume lift activities. However, there are significant opportunities to increase oil production and optimize gas injection. An Immiscible-Water-Alternating-Gas injection (IWAG) process was carried out on two composite samples extracted from the Mauddud reservoir of the Bahrain Field. The resulting production and pressure profiles were history matched by using hysteresis and three-phase relative permeability modeling options. Representative relative permeability and capillary pressure curves with the associated hysteresis and three- phase relative permeability parameters were obtained by history matching the experimental IWAG flood results. The history match was carried out by generating the hysteresis parameters and relative permeability curve sets. Experimental results, including two-phase water/gas flood steady state and unsteady state results, were honored to the degree possible. In both composite samples, the IWAG process showed incremental recovery compared to the base case water and gas injection cases. The incremental recovery obtained (above 10% PV) was largely due to the reduction of gas relative permeability during three-phase flow. A maximum trapped gas saturation of 23% was used to history match the core-flood results. A sector model of the Mauddud reservoir was run using the relative permeability and hysteresis model parameters obtained from the history matching of the composite core-floods. A water and gas flood base case was run and compared to the IWAG sequence. The IWAG process showed incremental recovery compared to the base case water injection. In the up-dip pattern where the water saturation is low, IWAG recovers 3% more than base case gas injection, while gas injection recovers 5% more than the IWAG sequence in the down-dip pattern where water saturation is higher. The objective of introducing the Immiscible Water Alternating Gas process (IWAG) in Mauddud was to reduce gas production by controlling the mobility during the three-phase flow. Incremental oil, compared with gas and water injection was also to be evaluated. Three IWAG pilots were introduced after an extensive study on optimum locations. Two inverted 5-spot patterns and one line drive pattern were selected; each pattern is around 40 acre spacing, targeting Mauddud B interval. The original Water Alternating Gas (WAG) ratio was designed to be 1:3 (Water: Gas) and the WAG period was originally designed to be from three to six months based on simulation work. WAG ratio and duration optimization were subject to performance. After one year of cyclic injection, both inverted 5-spot patterns showed lack of resp
{"title":"Simulation and Performance of Immiscible WAG Pilots in Mauddud Reservoir Using Three Phase Relative Permeability with Hysteresis","authors":"A. Al-Muftah, Yusuf Buali, A. Mahmoud, Hamed AlGhadhban","doi":"10.2118/195103-MS","DOIUrl":"https://doi.org/10.2118/195103-MS","url":null,"abstract":"\u0000 The Bahrain Field, being the first oil discovery in the gulf region in 1932, is now in a mature stage of development. Crestal gas injection in the Mauddud reservoir has continued to be the strongest driving mechanism since 1938. Over the last five years, gas injection and fluid production rates have grown three folds with expanded drilling, workovers, and high volume lift activities. However, there are significant opportunities to increase oil production and optimize gas injection.\u0000 An Immiscible-Water-Alternating-Gas injection (IWAG) process was carried out on two composite samples extracted from the Mauddud reservoir of the Bahrain Field. The resulting production and pressure profiles were history matched by using hysteresis and three-phase relative permeability modeling options. Representative relative permeability and capillary pressure curves with the associated hysteresis and three- phase relative permeability parameters were obtained by history matching the experimental IWAG flood results. The history match was carried out by generating the hysteresis parameters and relative permeability curve sets. Experimental results, including two-phase water/gas flood steady state and unsteady state results, were honored to the degree possible. In both composite samples, the IWAG process showed incremental recovery compared to the base case water and gas injection cases. The incremental recovery obtained (above 10% PV) was largely due to the reduction of gas relative permeability during three-phase flow. A maximum trapped gas saturation of 23% was used to history match the core-flood results.\u0000 A sector model of the Mauddud reservoir was run using the relative permeability and hysteresis model parameters obtained from the history matching of the composite core-floods. A water and gas flood base case was run and compared to the IWAG sequence. The IWAG process showed incremental recovery compared to the base case water injection. In the up-dip pattern where the water saturation is low, IWAG recovers 3% more than base case gas injection, while gas injection recovers 5% more than the IWAG sequence in the down-dip pattern where water saturation is higher.\u0000 The objective of introducing the Immiscible Water Alternating Gas process (IWAG) in Mauddud was to reduce gas production by controlling the mobility during the three-phase flow. Incremental oil, compared with gas and water injection was also to be evaluated. Three IWAG pilots were introduced after an extensive study on optimum locations. Two inverted 5-spot patterns and one line drive pattern were selected; each pattern is around 40 acre spacing, targeting Mauddud B interval. The original Water Alternating Gas (WAG) ratio was designed to be 1:3 (Water: Gas) and the WAG period was originally designed to be from three to six months based on simulation work. WAG ratio and duration optimization were subject to performance. After one year of cyclic injection, both inverted 5-spot patterns showed lack of resp","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89220459","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}
Accurate estimation of the Original Gas in Place (OGIP) early in the reservoir life is fundamental as field development plans and ultimate recovery strongly depend on it. This is particularly relevant when the conventional material balance is not suitable due to the lack of pertinent shut-in pressure measurements. This paper presents a case history of a tight gas field in which we use flowing material balance technique and type curves for decline curve analysis to calculate OGIP by using only flowing pressure and rate data. The method uses fundamental pseudo-steady state theory, which determines that a plot of the rate-normalized pressure drop vs the pseudo-time produces a straight line with the slope of such line yielding the OGIP. The use of the pseudo time concept calls for the estimate of gas properties at the prevailing reservoir pressure which in turn is a function of the OGIP and the cumulative production. We propose an iterative scheme based on the Newton-Raphson method to compute the OGIP using the flowing material balance technique coupled with the conventional P/Z material balance. We illustrate the application of the method with the aid of synthetic examples as well as field cases obtained from low permeability gas reservoirs where no shut-in pressures are available. Results from the technique adequately compare with type-curve matching analysis. Furthermore, we demonstrate the problem can be transformed into an equivalent-liquid system and being analyzed with standard PTA techniques using the constant rate liquid solution. In absence of shut-in pressure information, the PSS analysis offers an attractive alternative to the conventional material balance method. Besides, the method only requires minimal phase behavior data in the case of gases rendering its application practical and convenient. Also, we describe how to transform the constant pressure problem into a constant rate one in order to apply standard PTA techniques. Additionally, this work demonstrates the importance of having automated wells with permanent gauges by enhancing the value of the information provided by them in the framework of an adequate and judicious reservoir management.
{"title":"OGIP Estimation from Boundary Dominated Data Using Normalized Variables: A Field Case Application in a Tight Gas HP/HT Field","authors":"Adolfo D'Windt, A. Al-Saffar","doi":"10.2118/195152-MS","DOIUrl":"https://doi.org/10.2118/195152-MS","url":null,"abstract":"\u0000 Accurate estimation of the Original Gas in Place (OGIP) early in the reservoir life is fundamental as field development plans and ultimate recovery strongly depend on it. This is particularly relevant when the conventional material balance is not suitable due to the lack of pertinent shut-in pressure measurements. This paper presents a case history of a tight gas field in which we use flowing material balance technique and type curves for decline curve analysis to calculate OGIP by using only flowing pressure and rate data.\u0000 The method uses fundamental pseudo-steady state theory, which determines that a plot of the rate-normalized pressure drop vs the pseudo-time produces a straight line with the slope of such line yielding the OGIP. The use of the pseudo time concept calls for the estimate of gas properties at the prevailing reservoir pressure which in turn is a function of the OGIP and the cumulative production. We propose an iterative scheme based on the Newton-Raphson method to compute the OGIP using the flowing material balance technique coupled with the conventional P/Z material balance.\u0000 We illustrate the application of the method with the aid of synthetic examples as well as field cases obtained from low permeability gas reservoirs where no shut-in pressures are available. Results from the technique adequately compare with type-curve matching analysis. Furthermore, we demonstrate the problem can be transformed into an equivalent-liquid system and being analyzed with standard PTA techniques using the constant rate liquid solution.\u0000 In absence of shut-in pressure information, the PSS analysis offers an attractive alternative to the conventional material balance method. Besides, the method only requires minimal phase behavior data in the case of gases rendering its application practical and convenient. Also, we describe how to transform the constant pressure problem into a constant rate one in order to apply standard PTA techniques. Additionally, this work demonstrates the importance of having automated wells with permanent gauges by enhancing the value of the information provided by them in the framework of an adequate and judicious reservoir management.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83644524","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}
Soma Chakraborty, S. Lehrer, Jagrut Jani, S. Ramachandran
Sour production from offshore and land-based wells causes hydrogen sulfide (H2S) release during downhole and topsides operations. Improper handling of H2S can lead to serious environmental and safety concerns as well as numerous corrosion and compliance issues. Consequently, H2S can add significantly to the total cost of well operations. The application of efficient H2S management technologies can reduce environmental and safety concerns, enable the use of lower-cost materials, and comply with H2S specifications. To remove H2S from mixed production applications, several chemistries are commonly used. The most common are triazines, glyoxal, and metal-based chemistries. Although each can be effective to a certain extent, these technologies have issues with efficiency or they can create serious side issues. The reaction of triazines with H2S in mixed production is highly inefficient and it creates scaling. Glyoxals suffer from poor efficiency, thermal instability, and corrosivity. The metal-based chemistries are the most efficient in mixed production, but in certain application regimes they can create serious solids and emulsion issues. These challenges can increase CAPEX and OPEX as well as lead to significant downtime and lost production. To overcome issues with currently used chemistries in mixed sour production, extensive research was conducted to identify chemistry that would efficiently remove H2S while minimizing negative side effects. Systematic evaluation was performed for a series of chemistries to compare the scavenging efficiency, with a special emphasis on mixed production systems. Focus was also given on studying the associated side effects like emulsification tendency, scaling tendency, etc. to ensure the chemistry had no/minimal side effects seen by the more conventional chemistries. A high-throughput lab technique is presented that was designed to mimic scavenging tendency in sour mixed production environment. A continuous gas flow testing technique that helped study the reaction kinetics is also described. Laboratory and pre-field results proved the efficacy of the new non-MEA, non-triazine chemistry in mitigating H2S in upstream, midstream and downstream applications while being especially efficient in mixed production systems. Laboratory testing proved the chemistry to be highly efficient compared to triazine in mixed production systems. Results also indicated the chemistry is non-emulsion forming and has very little scaling tendency. Testing conducted in the field demonstrated that the new chemistry cost-effectively removes H2S and meets the operator specifications. The novel, non-triazine scavenger technology has significantly better performance than triazine, no emulsion concerns, acceptable HSE, non-corrosive effects, and less downstream concern than MEA triazine or metal-based scavengers. The new and differentiated chemistry reduces CAPEX and OPEX, drives productivity, improves reliability and reduces non-productive tim
{"title":"Cost-Effective Sour Management in Mixed Production Systems","authors":"Soma Chakraborty, S. Lehrer, Jagrut Jani, S. Ramachandran","doi":"10.2118/194884-MS","DOIUrl":"https://doi.org/10.2118/194884-MS","url":null,"abstract":"\u0000 Sour production from offshore and land-based wells causes hydrogen sulfide (H2S) release during downhole and topsides operations. Improper handling of H2S can lead to serious environmental and safety concerns as well as numerous corrosion and compliance issues. Consequently, H2S can add significantly to the total cost of well operations. The application of efficient H2S management technologies can reduce environmental and safety concerns, enable the use of lower-cost materials, and comply with H2S specifications. To remove H2S from mixed production applications, several chemistries are commonly used. The most common are triazines, glyoxal, and metal-based chemistries. Although each can be effective to a certain extent, these technologies have issues with efficiency or they can create serious side issues. The reaction of triazines with H2S in mixed production is highly inefficient and it creates scaling. Glyoxals suffer from poor efficiency, thermal instability, and corrosivity. The metal-based chemistries are the most efficient in mixed production, but in certain application regimes they can create serious solids and emulsion issues. These challenges can increase CAPEX and OPEX as well as lead to significant downtime and lost production. To overcome issues with currently used chemistries in mixed sour production, extensive research was conducted to identify chemistry that would efficiently remove H2S while minimizing negative side effects.\u0000 Systematic evaluation was performed for a series of chemistries to compare the scavenging efficiency, with a special emphasis on mixed production systems. Focus was also given on studying the associated side effects like emulsification tendency, scaling tendency, etc. to ensure the chemistry had no/minimal side effects seen by the more conventional chemistries. A high-throughput lab technique is presented that was designed to mimic scavenging tendency in sour mixed production environment. A continuous gas flow testing technique that helped study the reaction kinetics is also described.\u0000 Laboratory and pre-field results proved the efficacy of the new non-MEA, non-triazine chemistry in mitigating H2S in upstream, midstream and downstream applications while being especially efficient in mixed production systems. Laboratory testing proved the chemistry to be highly efficient compared to triazine in mixed production systems. Results also indicated the chemistry is non-emulsion forming and has very little scaling tendency. Testing conducted in the field demonstrated that the new chemistry cost-effectively removes H2S and meets the operator specifications.\u0000 The novel, non-triazine scavenger technology has significantly better performance than triazine, no emulsion concerns, acceptable HSE, non-corrosive effects, and less downstream concern than MEA triazine or metal-based scavengers. The new and differentiated chemistry reduces CAPEX and OPEX, drives productivity, improves reliability and reduces non-productive tim","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77239397","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}
Hashim Al-Sadah, Mohannad A. Abo Khamseen, A. Al-Ghamdi, Ali Fardan
As the electric submersible pump (ESP) population increases, the requirement for continuous operation is required to ensure optimum oil sweep rather than depending on fewer number of ESPs. ESP outages, shutdowns and underperforming pumps have to be minimized to reduce operational cost and deferred production. In efforts to reduce pumps downtime, ESP monitoring operations were centralized in a production surveillance and optimization center. This paper illustrates the practices followed in the hub to enhance productivity, by preventing ESP trips and failures, and conducting optimization initiatives through collaborative efforts with different parties. By remote monitoring of real-time data of downhole sensor readings and surface data, the hub can identify ESP units operating in conditions that could lead to shutdowns and are identified to be preventable ESP trips. By capturing and predicting the downtime events, the objectives of reducing ESP downtime and production deferral is achieved. The hub monitors the individual unit's parameters with its operational confines to ensure that the ESP is running within the preferred boundaries to preserve the equipment's electrical and mechanical health. The observed conditions are referenced against the design and actions are taken accordingly to avert unnecessary trips. Upon the deployment of ESP monitoring, many benefits were realized ranging from improved asset performance to raising efficiency of manpower usage besides saving time. Deferred production was avoided through eliminating preventable trips under ESP monitoring. This practice not only prevents ESP downtime, but also has the goal of improving ESP efficiency levels, regarding motor and pump performance. Proactive measures are crucial in ESP production operations. In events where a probable ESP trip is predicted and actions are taken to optimize its operating conditions to prevent the trip, the number of ESP outages at the field level is reduced, thereby helping to sustain a healthy ESP well life cycle.
{"title":"Proactive Utilization of ESP Performance Monitoring to Enhance Productivity","authors":"Hashim Al-Sadah, Mohannad A. Abo Khamseen, A. Al-Ghamdi, Ali Fardan","doi":"10.2118/194925-MS","DOIUrl":"https://doi.org/10.2118/194925-MS","url":null,"abstract":"\u0000 As the electric submersible pump (ESP) population increases, the requirement for continuous operation is required to ensure optimum oil sweep rather than depending on fewer number of ESPs. ESP outages, shutdowns and underperforming pumps have to be minimized to reduce operational cost and deferred production. In efforts to reduce pumps downtime, ESP monitoring operations were centralized in a production surveillance and optimization center. This paper illustrates the practices followed in the hub to enhance productivity, by preventing ESP trips and failures, and conducting optimization initiatives through collaborative efforts with different parties.\u0000 By remote monitoring of real-time data of downhole sensor readings and surface data, the hub can identify ESP units operating in conditions that could lead to shutdowns and are identified to be preventable ESP trips. By capturing and predicting the downtime events, the objectives of reducing ESP downtime and production deferral is achieved. The hub monitors the individual unit's parameters with its operational confines to ensure that the ESP is running within the preferred boundaries to preserve the equipment's electrical and mechanical health. The observed conditions are referenced against the design and actions are taken accordingly to avert unnecessary trips.\u0000 Upon the deployment of ESP monitoring, many benefits were realized ranging from improved asset performance to raising efficiency of manpower usage besides saving time. Deferred production was avoided through eliminating preventable trips under ESP monitoring. This practice not only prevents ESP downtime, but also has the goal of improving ESP efficiency levels, regarding motor and pump performance.\u0000 Proactive measures are crucial in ESP production operations. In events where a probable ESP trip is predicted and actions are taken to optimize its operating conditions to prevent the trip, the number of ESP outages at the field level is reduced, thereby helping to sustain a healthy ESP well life cycle.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91351515","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}
The water barrier performance of high density polyethyelene (HDPE) nanocomposites with different graphene thicknesses and aspect ratios was investigated. Three graphenes with differing thicknesses and aspect ratios were considered for this work. The graphene was blended into the polymer HDPE matrix using a heated internal mixer. The best performing graphene in terms of improved barrier performance was determined to be the one that is thinnest and with the highest aspect ratio. This graphene was further studied for the effects of loading, whereby samples with 0.005, 0.01 and 0.10 wt% graphene, revealed no significant difference between them for enhanced barrier performance. In addition, the degree of crystallinity was also measured and compared between the unmodified and the three graphene modified HDPE. Between the three graphene-HDPE variants, there was no discernible difference in the level of crystallisation of the HDPE. However, it was shown that crystallinity improves by some 15%, corresponding to a measured degree of crystallinity of 65% for the graphene-HDPE, versus 56% for the unmodified HDPE. Thermal stability, on the other hand, did not improve with addition of the three graphenes used in this work. It is believed that the graphene loading used in this work was is low to produce any observable enhancement in thermal stability.
{"title":"Barrier and Thermal Performance of Graphene-HDPE Nanocomposites for Pipeline Liner Application","authors":"M.S.F. Samsudin, Murniyati Ahmad Mahtar, K. Leong","doi":"10.2118/195069-MS","DOIUrl":"https://doi.org/10.2118/195069-MS","url":null,"abstract":"\u0000 The water barrier performance of high density polyethyelene (HDPE) nanocomposites with different graphene thicknesses and aspect ratios was investigated. Three graphenes with differing thicknesses and aspect ratios were considered for this work. The graphene was blended into the polymer HDPE matrix using a heated internal mixer. The best performing graphene in terms of improved barrier performance was determined to be the one that is thinnest and with the highest aspect ratio. This graphene was further studied for the effects of loading, whereby samples with 0.005, 0.01 and 0.10 wt% graphene, revealed no significant difference between them for enhanced barrier performance. In addition, the degree of crystallinity was also measured and compared between the unmodified and the three graphene modified HDPE. Between the three graphene-HDPE variants, there was no discernible difference in the level of crystallisation of the HDPE. However, it was shown that crystallinity improves by some 15%, corresponding to a measured degree of crystallinity of 65% for the graphene-HDPE, versus 56% for the unmodified HDPE. Thermal stability, on the other hand, did not improve with addition of the three graphenes used in this work. It is believed that the graphene loading used in this work was is low to produce any observable enhancement in thermal stability.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"134 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88903732","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}
Determination of mineral rock composition is an important part of unconventional reservoir formation evaluation because the mineral composition affects hydraulic fracture generation and propagation. Two types of models are usually used for mineralogy modeling—deterministic and stochastic. Both models apply mathematical representations of the logging tool responses; however, stochastic modeling has become more popular due to its consideration of random distributions in the predictor and target variables. Stochastic mineralogy modeling algorithms usually produce solutions by minimizing a function reflecting the differences between the measured and modeled responses. However, due to the non-uniqueness inherent in inversion methods, the solution may not provide petrophysically meaningful results. To avoid producing compromised results, the use of geological constraints is proposed to represent the geological relations between the unknown parameters (inversion variables), leading to a more meaningful mineralogy model. The proposed algorithm incorporates probability functions to generate mineralogical solutions representing geologically and petrophysically sound results. The weight assigned to the penalties in the cost function depends on the probability function assigned to the constraints. Two models are presented using the proposed algorithm: a pyrite-anhydrite constraint based on the iron and sulfur ratio, and a K-feldspar-albite constraint based on the thorium and potassium ratio. Data sets from several different shale plays, from across North America, are processed using the proposed algorithm. The mineral sets are complex and vary from one play to another. The results show excellent agreement with the available core X-ray diffraction measurements. The study demonstrates that the proposed constraints provide an effective improvement, in integrated formation evaluation, especially in unconventional reservoirs with highly complex mineralogy.
{"title":"Use of Geological Constraints in Multi-Mineral Modeling for Unconventional Reservoirs","authors":"Z. Hao, A. Nora, Mendez Freddy, Hanif Amer","doi":"10.2118/194745-MS","DOIUrl":"https://doi.org/10.2118/194745-MS","url":null,"abstract":"\u0000 Determination of mineral rock composition is an important part of unconventional reservoir formation evaluation because the mineral composition affects hydraulic fracture generation and propagation. Two types of models are usually used for mineralogy modeling—deterministic and stochastic. Both models apply mathematical representations of the logging tool responses; however, stochastic modeling has become more popular due to its consideration of random distributions in the predictor and target variables. Stochastic mineralogy modeling algorithms usually produce solutions by minimizing a function reflecting the differences between the measured and modeled responses. However, due to the non-uniqueness inherent in inversion methods, the solution may not provide petrophysically meaningful results. To avoid producing compromised results, the use of geological constraints is proposed to represent the geological relations between the unknown parameters (inversion variables), leading to a more meaningful mineralogy model.\u0000 The proposed algorithm incorporates probability functions to generate mineralogical solutions representing geologically and petrophysically sound results. The weight assigned to the penalties in the cost function depends on the probability function assigned to the constraints. Two models are presented using the proposed algorithm: a pyrite-anhydrite constraint based on the iron and sulfur ratio, and a K-feldspar-albite constraint based on the thorium and potassium ratio.\u0000 Data sets from several different shale plays, from across North America, are processed using the proposed algorithm. The mineral sets are complex and vary from one play to another. The results show excellent agreement with the available core X-ray diffraction measurements. The study demonstrates that the proposed constraints provide an effective improvement, in integrated formation evaluation, especially in unconventional reservoirs with highly complex mineralogy.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87035683","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}
Understanding the full-cycle cost of oil and gas exploration, development, and production is critical for petroleum producers and all players in the oil and gas industry. In particular, full-cycle cost assessment is used for corporate planning, acquisitions, operational improvements, project control, and risk management. The challenge is to ensure that full-cycle cost assessment is done accurately and on a consistent basis across different jurisdictions, companies, and geographic areas. Without knowing the full-cycle cost on a consistent basis worldwide, it is impossible to assess capital investment, forecast production from different areas, forecast prices, or assess other factors influencing the world market for oil and gas. This paper discusses the methodology for and the results of full-cycle cost assessment worldwide. This paper describes a methodology for full-cycle cost assessment that ensures data quality and consistency. It also provides examples of full-cycle cost assessment for major projects worldwide. The results of analysis help to predict long-term pricing trends, determine areas where production will grow or decline, and estimate capital expenditure in the next 10–20 years based on the most recent and most consistent data.
{"title":"Comparative Analysis of Full-Cycle Cost of Oil and Gas Exploration, Development and Production World-Wide","authors":"L. Virine, S. Mccoskey","doi":"10.2118/194906-MS","DOIUrl":"https://doi.org/10.2118/194906-MS","url":null,"abstract":"\u0000 Understanding the full-cycle cost of oil and gas exploration, development, and production is critical for petroleum producers and all players in the oil and gas industry. In particular, full-cycle cost assessment is used for corporate planning, acquisitions, operational improvements, project control, and risk management. The challenge is to ensure that full-cycle cost assessment is done accurately and on a consistent basis across different jurisdictions, companies, and geographic areas. Without knowing the full-cycle cost on a consistent basis worldwide, it is impossible to assess capital investment, forecast production from different areas, forecast prices, or assess other factors influencing the world market for oil and gas. This paper discusses the methodology for and the results of full-cycle cost assessment worldwide.\u0000 This paper describes a methodology for full-cycle cost assessment that ensures data quality and consistency. It also provides examples of full-cycle cost assessment for major projects worldwide. The results of analysis help to predict long-term pricing trends, determine areas where production will grow or decline, and estimate capital expenditure in the next 10–20 years based on the most recent and most consistent data.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90693429","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}
Abdul-Aziz Bassam, Ghazi Al-Besairi, Sulaiman Al-Dahash, Tomas Sierra, A. Mohamed, K. Heshmat
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying production-optimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells. The following are examples of problems identified in early stages: Detected wells with gas interference before they reached gas lockDetected wells with high flowline pressure before flowline blockage resulted from sand productionDetected wells with standing valve and/or traveling valve leak—resulting from sand production—before the pump stuck The availability of such a supervisory control and data acquisition (SCADA) system helped in guiding the operations team to further investigate only specific items from the field side to confirm the findings. The ability to remotely control the wells and remotely change configuration of the variable speed drive parameters enabled instant implementation and continuous production optimization. The powerful SCADA solution enabled creating short- and long-term plans and monitoring the behavior of wells while the implementation phase was executed. For the first time in South Ratqa in North Kuwait, the smart field approach was implemented in a thermal pilot using sucker rod pumps; and the results will be used as a reference for the upcoming projects in this area. Real-time monitoring and data storage in a single database with an analysis engine provided fully automated surveillance and the capability of remotely controlling and applying required actions for production optimization.
{"title":"Production Optimization Challenges and Solutions for Heavy Oil - North Kuwait","authors":"Abdul-Aziz Bassam, Ghazi Al-Besairi, Sulaiman Al-Dahash, Tomas Sierra, A. Mohamed, K. Heshmat","doi":"10.2118/194809-MS","DOIUrl":"https://doi.org/10.2118/194809-MS","url":null,"abstract":"\u0000 The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying production-optimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine.\u0000 Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions.\u0000 The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells.\u0000 Recording in the database a \"tracking item\" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.\u0000 The following are examples of problems identified in early stages: Detected wells with gas interference before they reached gas lockDetected wells with high flowline pressure before flowline blockage resulted from sand productionDetected wells with standing valve and/or traveling valve leak—resulting from sand production—before the pump stuck\u0000 The availability of such a supervisory control and data acquisition (SCADA) system helped in guiding the operations team to further investigate only specific items from the field side to confirm the findings. The ability to remotely control the wells and remotely change configuration of the variable speed drive parameters enabled instant implementation and continuous production optimization. The powerful SCADA solution enabled creating short- and long-term plans and monitoring the behavior of wells while the implementation phase was executed.\u0000 For the first time in South Ratqa in North Kuwait, the smart field approach was implemented in a thermal pilot using sucker rod pumps; and the results will be used as a reference for the upcoming projects in this area. Real-time monitoring and data storage in a single database with an analysis engine provided fully automated surveillance and the capability of remotely controlling and applying required actions for production optimization.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"204 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90488907","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}
Basirudin Djamaluddin, P. Prabhakar, Baburaj James, Anas Muzakir, Hussain AlMayad
Real-time data stream in the format of WITSML which can have frequency as low as 1 Hz is one of the best candidate to produce KPIs for the drilling operation activity. The KPIs generated from this calculation will have a relationship with other information from other data sources, known as metadata. The question is how can this KPI information be utilized for further analysis, wider/more complex analysis process which needs to be combined with metadata? An OLTP model is not the recommended model for data analytics but OLAP is. Another question is how will this data be stored in terms of the physical storage? We argue to use column-oriented for the physical storage which can perform analytical queries 10x to 30x faster than the row-oriented storage. The implementation of an OLAP model for storing KPIs data is proven to improve the performance of the analytical query significantly and combined with the implementation of column-oriented in the OLAP model improves more performance. This concludes that the implementation of OLAP with column-oriented data model can be used as the solid foundation for storing KPI data.
{"title":"Real-Time Drilling Operation Activity Analysis Data Modelling with Multidimensional Approach and Column-Oriented Storage","authors":"Basirudin Djamaluddin, P. Prabhakar, Baburaj James, Anas Muzakir, Hussain AlMayad","doi":"10.2118/194701-MS","DOIUrl":"https://doi.org/10.2118/194701-MS","url":null,"abstract":"\u0000 Real-time data stream in the format of WITSML which can have frequency as low as 1 Hz is one of the best candidate to produce KPIs for the drilling operation activity. The KPIs generated from this calculation will have a relationship with other information from other data sources, known as metadata.\u0000 The question is how can this KPI information be utilized for further analysis, wider/more complex analysis process which needs to be combined with metadata? An OLTP model is not the recommended model for data analytics but OLAP is. Another question is how will this data be stored in terms of the physical storage? We argue to use column-oriented for the physical storage which can perform analytical queries 10x to 30x faster than the row-oriented storage.\u0000 The implementation of an OLAP model for storing KPIs data is proven to improve the performance of the analytical query significantly and combined with the implementation of column-oriented in the OLAP model improves more performance. This concludes that the implementation of OLAP with column-oriented data model can be used as the solid foundation for storing KPI data.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90883510","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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