Arafa Al Harthy, Khalid Al Habsi, Khalid Al Hinai, Stuart Walley
The conventional well stimulation treatments have been used in the oil and gas wells for long time to remove formation damage or skin in order to enhance the well production and be able to achieve economic rates. Wireline Applied Stimulation Pulsing (WASP®) is a prominent new technology that is gaining more grounds in the well stimulation for oil producer and water injector wells. WASP® is an electro-hydraulic technology that generates repeatable, high power hydraulic pressure pulses downhole over the entire desired interval. The repeated pulsing stimulates the near wellbore area, breaks up scale and causing tensile failures in formation rock, thus creating mini fractures/fissures for new flow paths and removing formation damage or skin caused by scale, fines etc. that were blocking perforations, slotted liners, sand screens or gravel packs, resulting in improved inflow. Petrogas Exploration and Development recently conducted a WASP® campaign trial that is the first application in the middle east in four vertical wells in the south of Oman oil fields. The wells were Well-A, Well-B, Well-C and Well-D. The vertical wells were completed on the Gharif and Al Khlata sandstone oil reservoirs, which contain relatively medium oil with a viscosity range of 44-239 cP. All the pay zones were perforated, except for Well-B which was completed with gravel pack. The wells were completed with artificial lift including PCP pumps and beam pumps with polish rod strings. It was understood that the poor/low production performance of the candidate wells was due to the high skin, caused by the damaged gravel pack and plugged perforations. The WASP® tool specifications that was run for the treatments of the wells were 2.750" in diameter, and the length was approximately 11.6 m. The conveyance was on electrical wireline cable by using a standard logging truck. The results of the WASP® treatments jobs have shown mixed results but generally Well-A/B, Well-C and Well-D showed improvement in well performance and consequently in the oil gains. In fact, in Well-C in Aseel field had the highest production rate increased by more than threefold - a remarkable improvement. The other wells are still in the monitoring stage. The operation performance of WASP® treatments went smoothly without any operational issues or lost time in all the jobs. WASP® technology demonstrated that it is an attractive alternative method to the conventional well stimulation methods that involve the use of hydraulic fracturing and injection of acid, solvents and deimulsifiers. These conventional well stimulation methods have limitations in the treatment of the pay zone and operationally intensive. WASP® technology is proven to be more effective, safe (HSE compliant), less time consuming and thus cost effective. Petrogas is now considering applying the WASP® technology to the water injectors.
{"title":"The First Middle East Unconventional Well Stimulation Treatment by Applying WASP® Technology: Field Cases","authors":"Arafa Al Harthy, Khalid Al Habsi, Khalid Al Hinai, Stuart Walley","doi":"10.2118/195057-MS","DOIUrl":"https://doi.org/10.2118/195057-MS","url":null,"abstract":"\u0000 The conventional well stimulation treatments have been used in the oil and gas wells for long time to remove formation damage or skin in order to enhance the well production and be able to achieve economic rates.\u0000 Wireline Applied Stimulation Pulsing (WASP®) is a prominent new technology that is gaining more grounds in the well stimulation for oil producer and water injector wells. WASP® is an electro-hydraulic technology that generates repeatable, high power hydraulic pressure pulses downhole over the entire desired interval. The repeated pulsing stimulates the near wellbore area, breaks up scale and causing tensile failures in formation rock, thus creating mini fractures/fissures for new flow paths and removing formation damage or skin caused by scale, fines etc. that were blocking perforations, slotted liners, sand screens or gravel packs, resulting in improved inflow.\u0000 Petrogas Exploration and Development recently conducted a WASP® campaign trial that is the first application in the middle east in four vertical wells in the south of Oman oil fields. The wells were Well-A, Well-B, Well-C and Well-D. The vertical wells were completed on the Gharif and Al Khlata sandstone oil reservoirs, which contain relatively medium oil with a viscosity range of 44-239 cP. All the pay zones were perforated, except for Well-B which was completed with gravel pack. The wells were completed with artificial lift including PCP pumps and beam pumps with polish rod strings. It was understood that the poor/low production performance of the candidate wells was due to the high skin, caused by the damaged gravel pack and plugged perforations. The WASP® tool specifications that was run for the treatments of the wells were 2.750\" in diameter, and the length was approximately 11.6 m. The conveyance was on electrical wireline cable by using a standard logging truck.\u0000 The results of the WASP® treatments jobs have shown mixed results but generally Well-A/B, Well-C and Well-D showed improvement in well performance and consequently in the oil gains. In fact, in Well-C in Aseel field had the highest production rate increased by more than threefold - a remarkable improvement. The other wells are still in the monitoring stage. The operation performance of WASP® treatments went smoothly without any operational issues or lost time in all the jobs. WASP® technology demonstrated that it is an attractive alternative method to the conventional well stimulation methods that involve the use of hydraulic fracturing and injection of acid, solvents and deimulsifiers. These conventional well stimulation methods have limitations in the treatment of the pay zone and operationally intensive. WASP® technology is proven to be more effective, safe (HSE compliant), less time consuming and thus cost effective. Petrogas is now considering applying the WASP® technology to the water injectors.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84619419","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}
Arctic is widely considering as the last world biggest storehouse of natural resources. But its unique nature should always remain the main concern for all the energy projects development in this area. To achieve this development of the Arctic should go along with innovative technologies development. The ambition of this paper is to provide assessment of main Arctic projects on international energy markets development.
{"title":"Development of the Arctic and its Impact on International Energy Market","authors":"I. Akimova","doi":"10.2118/195070-MS","DOIUrl":"https://doi.org/10.2118/195070-MS","url":null,"abstract":"\u0000 Arctic is widely considering as the last world biggest storehouse of natural resources. But its unique nature should always remain the main concern for all the energy projects development in this area. To achieve this development of the Arctic should go along with innovative technologies development. The ambition of this paper is to provide assessment of main Arctic projects on international energy markets development.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79106505","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}
Drilling operations generate much information, such as daily drilling reports and reports generated by service companies, support personnel, and other stakeholders. These reports can be unstructured with information presented in a variety of formats. The extraction of this information is frequently challenging, which limits its use in future projects. Natural language processing provides an efficient way of mining and obtaining knowledge. This paper demonstrates how these techniques were used to analyze vast amounts of historical documents to quickly rank well complexity and determine which aspects of drilling operations were most critical. Sentiment analysis can be used to classify documents and other pieces of information into separate categories. In social media, it is used to analyze the collective perception of a given trending item. The technique was used here to classify wells into two ranked categorized lists. First, a classification listed wells by drilling issues. Second, a complexity ranking was defined so that each well could be classified as easy or difficult to drill. To build the sentiment analysis tool, a random set of training wells and their respective documents were selected. From these documents, a list of words was identified in what became known as highlighting sessions. During these sessions, subject matter experts (SMEs) classified words found in the documents. This "bag of words" was then used to train a classifier capable of ranking the wells related to the documents. A probability was associated to each well, providing a likelihood of inclusion in a given category. The methodology proved to be successful, ranking drilling documents in both defined category sets. Results show that the list of ranked wells can be used by SMEs to identify which wells are relevant and deserve detailed analysis. The list generated for both categories provided a guideline for further analysis, particularly identifying wells with little value. Results also showed the importance of correctly developing a list of words, an adequate training set, and the language used, as well as the need for SMEs to produce the final analysis. The technology showed promising results with real-world applications being conceivable with its current level of maturity. However, the results also indicated room for improving its effectiveness by refining the highlighting sessions, word lists, types of classifier used, and final ranking methodology. The use of methods and technology to help improve and enable the analysis of unstructured data in the drilling space should increase over time. This paper shows how current technology can already be used in practical real-life cases to produce tangible value.
{"title":"Implementing a Drilling Reporting Data Mining Tool Using Natural Language Processing Sentiment Analysis Techniques","authors":"P. Kowalchuk","doi":"10.2118/194961-MS","DOIUrl":"https://doi.org/10.2118/194961-MS","url":null,"abstract":"\u0000 Drilling operations generate much information, such as daily drilling reports and reports generated by service companies, support personnel, and other stakeholders. These reports can be unstructured with information presented in a variety of formats. The extraction of this information is frequently challenging, which limits its use in future projects. Natural language processing provides an efficient way of mining and obtaining knowledge. This paper demonstrates how these techniques were used to analyze vast amounts of historical documents to quickly rank well complexity and determine which aspects of drilling operations were most critical.\u0000 Sentiment analysis can be used to classify documents and other pieces of information into separate categories. In social media, it is used to analyze the collective perception of a given trending item. The technique was used here to classify wells into two ranked categorized lists. First, a classification listed wells by drilling issues. Second, a complexity ranking was defined so that each well could be classified as easy or difficult to drill. To build the sentiment analysis tool, a random set of training wells and their respective documents were selected. From these documents, a list of words was identified in what became known as highlighting sessions. During these sessions, subject matter experts (SMEs) classified words found in the documents. This \"bag of words\" was then used to train a classifier capable of ranking the wells related to the documents. A probability was associated to each well, providing a likelihood of inclusion in a given category.\u0000 The methodology proved to be successful, ranking drilling documents in both defined category sets. Results show that the list of ranked wells can be used by SMEs to identify which wells are relevant and deserve detailed analysis. The list generated for both categories provided a guideline for further analysis, particularly identifying wells with little value. Results also showed the importance of correctly developing a list of words, an adequate training set, and the language used, as well as the need for SMEs to produce the final analysis. The technology showed promising results with real-world applications being conceivable with its current level of maturity. However, the results also indicated room for improving its effectiveness by refining the highlighting sessions, word lists, types of classifier used, and final ranking methodology.\u0000 The use of methods and technology to help improve and enable the analysis of unstructured data in the drilling space should increase over time. This paper shows how current technology can already be used in practical real-life cases to produce tangible value.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85404011","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Oil Fingerprinting by gas chromatography techniques are among the most sensitive and accurate tools utilized to study reservoir compartmentalization and oil to oil correlations. The greatest challenge of the technique, however, lies in recognizing and identifying if any oils have undergone post-generative alteration processes such as water washing or biodegradation that may prohibit accurate correlation. These effects, even when subtle, may alter or transform oils resulting in misleading interpretations and invalid outcomes. Understanding the controls on the oil composition is critical for all fingerprinting studies and can promote new characterization methods to ensure any negative post-generative alteration effects are mitigated. The study aims to illustrate the use of various geochemical fingerprinting methods to assess the reservoir connectivity between two oil accumulations. Furthermore, the effect of water washing on the oil compositions, and its relationship with gas to oil ratio (GOR) and salinity were investigated. A total of 11 oil samples from an Ordovician siliciclastic formation across 10 locations in a field were analyzed for API gravity light hydrocarbons (C5-C7) and whole-oil fingerprinting (C8 to C20) gas chromatography (GC) characterization methods. Light hydrocarbons (LHC) analysis used to correlate different oils to their sources was interpreted using five specially selected source dependent ratios plotted in a C7 star diagram. If the oils have a similar pattern, this indicates a similar source and vice versa. The results suggest that the oils can be correlated to two different source rocks that charged the study area from independent northeast and southwest directions. A second set of light hydrocarbon ratios sensitive to water washing and biodegradation effects suggested a noticeable water washing trend increasing to the north. The whole-oil fingerprinting analysis employs a multivariate statistical model across all the samples to determine the most variant 12 ratios from the chromatograms to construct a specialized star diagram. From this analysis, five separate reservoir compartments were identified. It was further observed that a set of samples from a specific compartment differed in one of the 12 ratios. This ratio was plotted against the water washing transformation ratio from LHC and revealed a strong positive correlation. The difference in this ratio is attributed to water washing. Both parameters suggest that water washing possesses strong negative correlations with total dissolved salts (TDS) of the formation water and gas to oil ratio (GOR). These relationships accentuate the potential of utilizing the geochemical ratios to predict the GOR and consequently improve the production planning. The study shed the lights on the potential utilization of new rapid and cost-effective geochemical methods to predict some production engineering parameters.
{"title":"Reservoir Connectivity, Water Washing and Oil to Oil Correlation: An Integrated Geochemical & Petroleum Engineering Approach","authors":"B. Ghassal","doi":"10.2118/194957-MS","DOIUrl":"https://doi.org/10.2118/194957-MS","url":null,"abstract":"\u0000 Oil Fingerprinting by gas chromatography techniques are among the most sensitive and accurate tools utilized to study reservoir compartmentalization and oil to oil correlations. The greatest challenge of the technique, however, lies in recognizing and identifying if any oils have undergone post-generative alteration processes such as water washing or biodegradation that may prohibit accurate correlation. These effects, even when subtle, may alter or transform oils resulting in misleading interpretations and invalid outcomes. Understanding the controls on the oil composition is critical for all fingerprinting studies and can promote new characterization methods to ensure any negative post-generative alteration effects are mitigated.\u0000 The study aims to illustrate the use of various geochemical fingerprinting methods to assess the reservoir connectivity between two oil accumulations. Furthermore, the effect of water washing on the oil compositions, and its relationship with gas to oil ratio (GOR) and salinity were investigated.\u0000 A total of 11 oil samples from an Ordovician siliciclastic formation across 10 locations in a field were analyzed for API gravity light hydrocarbons (C5-C7) and whole-oil fingerprinting (C8 to C20) gas chromatography (GC) characterization methods. Light hydrocarbons (LHC) analysis used to correlate different oils to their sources was interpreted using five specially selected source dependent ratios plotted in a C7 star diagram. If the oils have a similar pattern, this indicates a similar source and vice versa.\u0000 The results suggest that the oils can be correlated to two different source rocks that charged the study area from independent northeast and southwest directions. A second set of light hydrocarbon ratios sensitive to water washing and biodegradation effects suggested a noticeable water washing trend increasing to the north. The whole-oil fingerprinting analysis employs a multivariate statistical model across all the samples to determine the most variant 12 ratios from the chromatograms to construct a specialized star diagram. From this analysis, five separate reservoir compartments were identified. It was further observed that a set of samples from a specific compartment differed in one of the 12 ratios. This ratio was plotted against the water washing transformation ratio from LHC and revealed a strong positive correlation. The difference in this ratio is attributed to water washing. Both parameters suggest that water washing possesses strong negative correlations with total dissolved salts (TDS) of the formation water and gas to oil ratio (GOR). These relationships accentuate the potential of utilizing the geochemical ratios to predict the GOR and consequently improve the production planning. The study shed the lights on the potential utilization of new rapid and cost-effective geochemical methods to predict some production engineering parameters.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 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":"91384298","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}
Crestal gas injection started in the Bahrain Field in 1938 and since then, 1,900 Bscf has been injected in Mauddud, the main oil producing reservoir in the Bahrain Field, creating a secondary gas cap. Furthermore, since 1965, an estimated 100 MMstb of Liquefied Petroleum Gas (LPG), or 14% of the bypassed oil, has been recovered from the secondary gas cap through stripping with the remaining oil volume in the secondary gas cap being approximately 700 MMstb. Today, the remaining oil saturation in the Mauddud gas cap is estimated to be approximately 40%. This paper presents the results of an extensive study that was made to forecast the Bahrain Field associated gas compositions and potential gas-liquids production recovery. Several forecast methodologies were used including data-driven analytical models, a compositional cross-section model, and a full-field compositional history matched model. The results of these forecasts and the conclusions are presented and compared. In this study, two scenarios of different gas compositions of injected gas and their impact on gas plant liquids recovery are explored. In addition, this paper addresses the challenges and uncertainties associated in forecasting the gas compositions and ways to overcome them. The data-driven models and compositional cross-section model were initially used, however, due to their inherent uncertainties, a full field compositional simulation model was necessary. This compositional model was history matched with a seven (7) component Equation of State (EOS) to capture the lighter hydrocarbon components. Moreover, this model was used in predicting the yield and composition of the existing gas recovery plant. The results from all methods recommend doubling the capacity of the existing plant, which was commissioned in late 2018. A comparative analysis found that data-driven models can be used for gas cycling when using the same gas injection compositions. However, data-driven models over-estimate the Liquefied Petroleum Gas (LPG) yield if leaner gas is used for gas injection, which is the case for the proposed gas plant expansion.
{"title":"Using Data Driven Analytical Models with Compositional Simulation in Doubling the LPG Production from Bahrain Field","authors":"A. Al-Muftah, Ebrahim AlOwainati, M. Mansoor","doi":"10.2118/194859-MS","DOIUrl":"https://doi.org/10.2118/194859-MS","url":null,"abstract":"\u0000 Crestal gas injection started in the Bahrain Field in 1938 and since then, 1,900 Bscf has been injected in Mauddud, the main oil producing reservoir in the Bahrain Field, creating a secondary gas cap. Furthermore, since 1965, an estimated 100 MMstb of Liquefied Petroleum Gas (LPG), or 14% of the bypassed oil, has been recovered from the secondary gas cap through stripping with the remaining oil volume in the secondary gas cap being approximately 700 MMstb. Today, the remaining oil saturation in the Mauddud gas cap is estimated to be approximately 40%.\u0000 This paper presents the results of an extensive study that was made to forecast the Bahrain Field associated gas compositions and potential gas-liquids production recovery. Several forecast methodologies were used including data-driven analytical models, a compositional cross-section model, and a full-field compositional history matched model. The results of these forecasts and the conclusions are presented and compared. In this study, two scenarios of different gas compositions of injected gas and their impact on gas plant liquids recovery are explored.\u0000 In addition, this paper addresses the challenges and uncertainties associated in forecasting the gas compositions and ways to overcome them. The data-driven models and compositional cross-section model were initially used, however, due to their inherent uncertainties, a full field compositional simulation model was necessary. This compositional model was history matched with a seven (7) component Equation of State (EOS) to capture the lighter hydrocarbon components. Moreover, this model was used in predicting the yield and composition of the existing gas recovery plant. The results from all methods recommend doubling the capacity of the existing plant, which was commissioned in late 2018. A comparative analysis found that data-driven models can be used for gas cycling when using the same gas injection compositions. However, data-driven models over-estimate the Liquefied Petroleum Gas (LPG) yield if leaner gas is used for gas injection, which is the case for the proposed gas plant expansion.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 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":"91113194","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}
O. Abdullatif, M. Osman, M. Yassin, M. Makkawi, Mohamed al-Farhan
The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone. The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles. The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other h
{"title":"Digital Outcrop Analog Reservoir Model of the Miocene Turbidite Sandstones, Midyan Area, Red Sea Region, Saudi Arabia","authors":"O. Abdullatif, M. Osman, M. Yassin, M. Makkawi, Mohamed al-Farhan","doi":"10.2118/195002-MS","DOIUrl":"https://doi.org/10.2118/195002-MS","url":null,"abstract":"\u0000 The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone.\u0000 The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles.\u0000 The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other h","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81508993","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 corrosion behaviour of API 5L X65 carbon steel was investigated under high pressure carbon dioxide environments, containing elevated hydrogen sulfide, to simulate the condition of high carbon dioxide-containing natural gas subsea pipelines. It was systematically studied under high pressure carbon dioxide (120 bars) with a variation in other key parameters (hydrogen sulfide concentration and temperature). The corrosion rates were tested using High Pressure and High Temperature (HPHT) autoclave and measured using the techniques such as linear polarisation resistance (LPR), potentiodynamic sweep measurements, iron count, weight loss (WL) and electrochemical impedance spectroscopy (EIS). The surface morphology and the composition of the corrosion product layers were analysed using Infinite Focus Microscope (IFM), X-ray diffraction (XRD), Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). The results showed that in the CO2- saturated water phase, the addition of 2000 ppm hydrogen sulfide (H2S) instantaneously decreased the corrosion rate of carbon steel API 5L X65 at both 25°C and 80°C. The surface morphology and the composition of the corrosion product layers reveal the formation of mackinawite. The inhibitive effect of hydrogen sulfide at elevated concentration was observed and contributed to the significant reduction in corrosion. The effect on corrosion was despite the fact that water chemistry equilibrium was unchanged with the presence of elevated hydrogen sulfide.
{"title":"The Effect of Elevated H2S on Corrosion Behaviour of API 5L X65 Carbon Steel in High Partial Pressure CO2 Environments","authors":"A. Z. Abas, A. Nor, M. Suhor, A. Rusli","doi":"10.2118/194873-MS","DOIUrl":"https://doi.org/10.2118/194873-MS","url":null,"abstract":"\u0000 The corrosion behaviour of API 5L X65 carbon steel was investigated under high pressure carbon dioxide environments, containing elevated hydrogen sulfide, to simulate the condition of high carbon dioxide-containing natural gas subsea pipelines. It was systematically studied under high pressure carbon dioxide (120 bars) with a variation in other key parameters (hydrogen sulfide concentration and temperature). The corrosion rates were tested using High Pressure and High Temperature (HPHT) autoclave and measured using the techniques such as linear polarisation resistance (LPR), potentiodynamic sweep measurements, iron count, weight loss (WL) and electrochemical impedance spectroscopy (EIS). The surface morphology and the composition of the corrosion product layers were analysed using Infinite Focus Microscope (IFM), X-ray diffraction (XRD), Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). The results showed that in the CO2- saturated water phase, the addition of 2000 ppm hydrogen sulfide (H2S) instantaneously decreased the corrosion rate of carbon steel API 5L X65 at both 25°C and 80°C. The surface morphology and the composition of the corrosion product layers reveal the formation of mackinawite. The inhibitive effect of hydrogen sulfide at elevated concentration was observed and contributed to the significant reduction in corrosion. The effect on corrosion was despite the fact that water chemistry equilibrium was unchanged with the presence of elevated hydrogen sulfide.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89186637","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}
Non-magnetic collars must be strong, tough, and corrosion resistant to withstand dynamic drillstring loads while also providing robust housings for measuring and logging-while-drilling (MWD/LWD) tool electronics. This paper describes a materials solution to problems related to the corrosion of drill collars in hostile well conditions. Typical nitrogen-strengthened chrome-manganese drill collar alloys are at risk of early retirement or downhole failure due to pitting, stress corrosion cracking (SCC), and sulfide stress cracking (SSC). Tool non-productive time due to increased maintenance, repair, overhaul frequency, and premature removal from service increases operating costs. The results of laboratory trials in conditions representative of active drilling basins show the differentiated performance of a chrome-nickel stainless steel and nickel-based alloy 718 relative to more common chrome-manganese stainless grades currently in wide-spread use. The pitting resistance, SCC resistance, and SSC resistance of both chrome-nickel stainless and nickel grade were found to be significantly better under wide ranging conditions and confirmed the capacity of both alloy systems to outlast incumbent drill collar grades.
{"title":"Increased Tool Life and Enhanced Reliability for Bottomhole Assemblies in Harsh Environments","authors":"K. Panda, Thomas Williams, A. Collins","doi":"10.2118/194784-MS","DOIUrl":"https://doi.org/10.2118/194784-MS","url":null,"abstract":"\u0000 Non-magnetic collars must be strong, tough, and corrosion resistant to withstand dynamic drillstring loads while also providing robust housings for measuring and logging-while-drilling (MWD/LWD) tool electronics. This paper describes a materials solution to problems related to the corrosion of drill collars in hostile well conditions. Typical nitrogen-strengthened chrome-manganese drill collar alloys are at risk of early retirement or downhole failure due to pitting, stress corrosion cracking (SCC), and sulfide stress cracking (SSC). Tool non-productive time due to increased maintenance, repair, overhaul frequency, and premature removal from service increases operating costs. The results of laboratory trials in conditions representative of active drilling basins show the differentiated performance of a chrome-nickel stainless steel and nickel-based alloy 718 relative to more common chrome-manganese stainless grades currently in wide-spread use. The pitting resistance, SCC resistance, and SSC resistance of both chrome-nickel stainless and nickel grade were found to be significantly better under wide ranging conditions and confirmed the capacity of both alloy systems to outlast incumbent drill collar grades.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 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":"87828410","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 technological revolution in hydraulic fracturing has occurred between early wellbore stimulation techniques and present day stimulation that has reduced cost and increased stimulation performance. Part of this revolution has been driven by the improved technology of frac plugs. This paper discusses how the evolution from cast iron frac plugs to composite plugs, then later to an interventionless stimulation completions process has enabled stimulation in extended-reach wellbores. Drillable frac plugs were initially created from cast iron. Although cast iron plugs met run-in requirements and pressure ratings, the time required to remove these plugs by milling was long. Composite frac plugs were developed to accelerate the mill-out process. The light weight of the composite frac plugs also enabled the frac plugs to be run into a horizontal section of the wellbore. This operational change, combined with the ease of milling the composite plugs, has paved the way for the horizontal completion market for the past 15 years. However, the use of composite frac plugs in extended-reach horizontal wells was limited by the need to drill out the plugs. The development of dissolvable frac plugs eliminated the need to drill out the plugs allowing operators to produce wells much sooner. This elimination of the drill-out step for dissolvable frac plugs has also enabled the successful completion of extended-reach horizontal wells which may be beyond the practical range of coiled tubing or jointed tubing. The need for efficient production in extended-reach wellbores has spurred the continuing evolution of hydraulic stimulation. This paper describes 20 years of new technology and field results to document the changes to the design and construction of frac plugs, as well as changes to the design and operation of the wellbore.
{"title":"Evolution of Frac Plug Technologies – Cast Iron to Composites to Dissolvable","authors":"Z. Walton, M. Fripp, Jesse C. Porter, Greg Vargus","doi":"10.2118/194802-MS","DOIUrl":"https://doi.org/10.2118/194802-MS","url":null,"abstract":"\u0000 A technological revolution in hydraulic fracturing has occurred between early wellbore stimulation techniques and present day stimulation that has reduced cost and increased stimulation performance. Part of this revolution has been driven by the improved technology of frac plugs. This paper discusses how the evolution from cast iron frac plugs to composite plugs, then later to an interventionless stimulation completions process has enabled stimulation in extended-reach wellbores.\u0000 Drillable frac plugs were initially created from cast iron. Although cast iron plugs met run-in requirements and pressure ratings, the time required to remove these plugs by milling was long. Composite frac plugs were developed to accelerate the mill-out process. The light weight of the composite frac plugs also enabled the frac plugs to be run into a horizontal section of the wellbore. This operational change, combined with the ease of milling the composite plugs, has paved the way for the horizontal completion market for the past 15 years. However, the use of composite frac plugs in extended-reach horizontal wells was limited by the need to drill out the plugs. The development of dissolvable frac plugs eliminated the need to drill out the plugs allowing operators to produce wells much sooner. This elimination of the drill-out step for dissolvable frac plugs has also enabled the successful completion of extended-reach horizontal wells which may be beyond the practical range of coiled tubing or jointed tubing.\u0000 The need for efficient production in extended-reach wellbores has spurred the continuing evolution of hydraulic stimulation. This paper describes 20 years of new technology and field results to document the changes to the design and construction of frac plugs, as well as changes to the design and operation of the wellbore.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82545716","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 reservoir compartmentalization structure and fluid contacts of a field are essential for determining the value of a reservoir asset and provide the two primary purposes of pressure gradient determination. Several new straightforward data-analytical methods have been developed to extract pressure gradient information based on physical properties of the reservoir and meta-analysis of derived pressure gradient information. These methods can be used to provide near real-time feedback about the pressure measurements quality. This paper describes two distinct methods to determine reservoir compartmentalization structure and fluid contacts. The first method implements statistical evolution to rapidly identify pressure gradients. The second method transforms identified pressure measurements into a meta-analytical visual representation of pressure gradients vs. depth with additional input from measurement consistency. Both methods rely on the accurate removal of pressure outlier data, such as that attributable to supercharging. A new technique using expert knowledge of physical constraints was implemented for reliable outlier removal. The two methods then diverge in subsequent conditioning of the data, but re-converge in adapting an efficient fitting method to extract the desired information. Both methods provide reliable removal of pressure data that are not related to formation fluid densities, regardless of reservoir number, fluid number, or fluid type. To date, the removal procedure removes more than 95% of outliers and retains more than 90% of accurate pressure data. Both methods also return the correct number and types of fluids. Although pressure gradient estimation can vary by up to 50% for fluid zones of less than 50 ft, the estimation error of the pressure gradients is reduced to less than 3% for fluid zones greater than 100 ft. Furthermore, fluid breaks can be calculated to within 8 ft for the statistical evolution method and to within 30 ft using the visual method. Finally, although the statistical evolution method is markedly faster than the visual method, both techniques provide feedback within a few minutes. The methods discussed provide feedback about the necessity to retake or take more pressure data during formation-pressure surveys within minutes. This feedback eliminates the delay in reservoir property estimation and greatly increases the reliability and quality of pressure data obtained. The methods presented also use a new application of data meta-analysis to reduce processing time and increase reliability.
{"title":"Automated Artificial Intelligent Pressure Gradient Analysis for Fluid Contact and Compartmentalization Analysis","authors":"D. Stark, C. M. Jones, Bin Dai, A. V. Zuilekom","doi":"10.2118/195083-MS","DOIUrl":"https://doi.org/10.2118/195083-MS","url":null,"abstract":"\u0000 The reservoir compartmentalization structure and fluid contacts of a field are essential for determining the value of a reservoir asset and provide the two primary purposes of pressure gradient determination. Several new straightforward data-analytical methods have been developed to extract pressure gradient information based on physical properties of the reservoir and meta-analysis of derived pressure gradient information. These methods can be used to provide near real-time feedback about the pressure measurements quality.\u0000 This paper describes two distinct methods to determine reservoir compartmentalization structure and fluid contacts. The first method implements statistical evolution to rapidly identify pressure gradients. The second method transforms identified pressure measurements into a meta-analytical visual representation of pressure gradients vs. depth with additional input from measurement consistency. Both methods rely on the accurate removal of pressure outlier data, such as that attributable to supercharging. A new technique using expert knowledge of physical constraints was implemented for reliable outlier removal. The two methods then diverge in subsequent conditioning of the data, but re-converge in adapting an efficient fitting method to extract the desired information.\u0000 Both methods provide reliable removal of pressure data that are not related to formation fluid densities, regardless of reservoir number, fluid number, or fluid type. To date, the removal procedure removes more than 95% of outliers and retains more than 90% of accurate pressure data. Both methods also return the correct number and types of fluids. Although pressure gradient estimation can vary by up to 50% for fluid zones of less than 50 ft, the estimation error of the pressure gradients is reduced to less than 3% for fluid zones greater than 100 ft. Furthermore, fluid breaks can be calculated to within 8 ft for the statistical evolution method and to within 30 ft using the visual method. Finally, although the statistical evolution method is markedly faster than the visual method, both techniques provide feedback within a few minutes.\u0000 The methods discussed provide feedback about the necessity to retake or take more pressure data during formation-pressure surveys within minutes. This feedback eliminates the delay in reservoir property estimation and greatly increases the reliability and quality of pressure data obtained. The methods presented also use a new application of data meta-analysis to reduce processing time and increase reliability.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"212 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76583086","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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