M. Abdelazim, N. Galin, A. Abri, I. Khanbashi, Khalsa Shamsi, Zeidi Badar, Ananda Pranava, Chris Rodger
The X-field is located in the North West of Oman. Drilling of more than 30 appraisal and development vertical wells is planned in the coming few years. Whilst drilling through the carbonate formations of Habshan, Jubaila and Tuwaiq Mountain in the existing 11 wells, total to partial mud losses were encountered in several wells due to the severe karstification. This led to significant cost increases and delays to the well delivery time. Utilizing the new wide azimuth seismic data and well maps, gives an indication of a loss zone intervals using the seismic attributes to assess the possibility of encountering the loss zone. The detection of the source of losses presents a big challenge; knowing the precise zones helps in optimizing the number of cement curing plugs thus a reduction in drilling days and cost. When losses occur; the drilling fluid moves from high pressure side (mud weight) to low pressure side (formation) causing a complete loss, where it expands rapidly and produces a turbulent flow that creates an acoustic signal and temperature anomaly. Modern acoustic logging tools, Chorus acoustic platform (Spectral Noise Log – SNL), coupled with fast and high precision temperature logging tools, Cascade thermal platform (High Precision Temperature – HPT), are capable to detect the subsequent acoustic and temperature anomalies in the drilling losses and indicate the loss zones. The chorus acoustic platform contains a new generation, high-sensitivity hydrophone – a piezo crystal element that records noise in a wide frequency range (0.1-60kHz). The Cascade thermal platform utilizes a super-sensitive platinum sensor with a response time of less than one second. The technology is already being used in critical oil and gas wells to identify tubing and casing leaks and address well integrity issues but, this is the first time it has been used in the open hole to identify the drilling mud losses in Oman. This paper presents the successful use of Chorus and Cascade platforms (SNL-HPT) in a Deep Gas well in X-Field, North of Oman, PDO Company, for identifying the total and partial loss zone across 12.25" hole. The well-A was drilled as an appraisal vertical gas deep well in one of X fields, North of Oman, and experienced fluid losses across 12.25" hole in carbonates formations. The top section was cased with 18 5/8" and 13 3/8" casings. Across the interval of interest, drill pipe was inside the borehole filled with water-based mud and the Chorus and Cascade logging tools (SNL-HPT) were conveyed by a slickline located inside the drill pipe.
{"title":"Detection of Drilling Loss Zones in Deep Gas Well Using Acoustic and High Precision Temperature Logging Technology, a Case Study from North of Oman","authors":"M. Abdelazim, N. Galin, A. Abri, I. Khanbashi, Khalsa Shamsi, Zeidi Badar, Ananda Pranava, Chris Rodger","doi":"10.2118/200283-ms","DOIUrl":"https://doi.org/10.2118/200283-ms","url":null,"abstract":"\u0000 The X-field is located in the North West of Oman. Drilling of more than 30 appraisal and development vertical wells is planned in the coming few years. Whilst drilling through the carbonate formations of Habshan, Jubaila and Tuwaiq Mountain in the existing 11 wells, total to partial mud losses were encountered in several wells due to the severe karstification. This led to significant cost increases and delays to the well delivery time.\u0000 Utilizing the new wide azimuth seismic data and well maps, gives an indication of a loss zone intervals using the seismic attributes to assess the possibility of encountering the loss zone. The detection of the source of losses presents a big challenge; knowing the precise zones helps in optimizing the number of cement curing plugs thus a reduction in drilling days and cost.\u0000 When losses occur; the drilling fluid moves from high pressure side (mud weight) to low pressure side (formation) causing a complete loss, where it expands rapidly and produces a turbulent flow that creates an acoustic signal and temperature anomaly. Modern acoustic logging tools, Chorus acoustic platform (Spectral Noise Log – SNL), coupled with fast and high precision temperature logging tools, Cascade thermal platform (High Precision Temperature – HPT), are capable to detect the subsequent acoustic and temperature anomalies in the drilling losses and indicate the loss zones.\u0000 The chorus acoustic platform contains a new generation, high-sensitivity hydrophone – a piezo crystal element that records noise in a wide frequency range (0.1-60kHz). The Cascade thermal platform utilizes a super-sensitive platinum sensor with a response time of less than one second. The technology is already being used in critical oil and gas wells to identify tubing and casing leaks and address well integrity issues but, this is the first time it has been used in the open hole to identify the drilling mud losses in Oman.\u0000 This paper presents the successful use of Chorus and Cascade platforms (SNL-HPT) in a Deep Gas well in X-Field, North of Oman, PDO Company, for identifying the total and partial loss zone across 12.25\" hole.\u0000 The well-A was drilled as an appraisal vertical gas deep well in one of X fields, North of Oman, and experienced fluid losses across 12.25\" hole in carbonates formations. The top section was cased with 18 5/8\" and 13 3/8\" casings. Across the interval of interest, drill pipe was inside the borehole filled with water-based mud and the Chorus and Cascade logging tools (SNL-HPT) were conveyed by a slickline located inside the drill pipe.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85439823","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}
Rady AbdelSamiee, Abdul Aziz Sariri, Safiya Hatmi, Mohammed Hinai, Carmen Hamm, Jasbindra Singh, Saif Hinai, S. Hamhami, N. Azri, Hatim Al Asmi, Yahya Farsi, Osama Abazeed
A new technology utilizing the Autonomous Inflow Control Device (AICD) has been used in horizontal wells producing from a viscous oil reservoir to restrict the unwanted water breakthrough and maximize the oil gain. The added benefit of greater reservoir contact has met with increased differential drawdown across the horizontal section to manage the reservoir heterogeneity. AICD is an active flow resistance element distributed along the length of the horizontal well-bore section to delay and reduce the proportions of the water breakthrough. The AICDs impose a relatively strong resistance for low-viscous fluids over the high viscous oil. This is due to the changes in the flow area internally in the AICD. With this technology, oil production can be increased while restricting the water inflow into the wellbore. The AICD operates without the need for human or surface interventions and electric or hydraulic power. AICD technology has been piloted in two new wells in two fields located in South Oman. The reservoir contains viscous oil (400-600 cp) and exhibits high inflow potential due to favourable rock properties and strong bottom water aquifer. Horizontal wells have been used to maximize reservoir oil contact and improve recovery from the reservoir. The wells, in general, produce oil with very high water cut (>95%). Two horizontal wells were drilled recently, and each well was completed with AICDs along a completed lateral length of 500 m. The AICDs managed in bringing down the water cut to less than 5% from 95% observed in the surrounding wells. The production behaviour has been sustained for nearly a year now. The success of the AICD trial has opened the doors for its wider use in reservoirs containing viscous oil. The AICD also has been tried in existing wells where it managed to reduce the gross and the water cut by 50% and increase the oil gain by 100%. Plans are also in place to extend the AICD trials in existing wells and reap the benefits by maximising oil production while decreasing the unwanted water production.
{"title":"Managing the High Water Cut Behavior in a De-Saturated Reservoir and Maximize the Oil Gain","authors":"Rady AbdelSamiee, Abdul Aziz Sariri, Safiya Hatmi, Mohammed Hinai, Carmen Hamm, Jasbindra Singh, Saif Hinai, S. Hamhami, N. Azri, Hatim Al Asmi, Yahya Farsi, Osama Abazeed","doi":"10.2118/200304-ms","DOIUrl":"https://doi.org/10.2118/200304-ms","url":null,"abstract":"\u0000 A new technology utilizing the Autonomous Inflow Control Device (AICD) has been used in horizontal wells producing from a viscous oil reservoir to restrict the unwanted water breakthrough and maximize the oil gain. The added benefit of greater reservoir contact has met with increased differential drawdown across the horizontal section to manage the reservoir heterogeneity.\u0000 AICD is an active flow resistance element distributed along the length of the horizontal well-bore section to delay and reduce the proportions of the water breakthrough. The AICDs impose a relatively strong resistance for low-viscous fluids over the high viscous oil. This is due to the changes in the flow area internally in the AICD. With this technology, oil production can be increased while restricting the water inflow into the wellbore. The AICD operates without the need for human or surface interventions and electric or hydraulic power.\u0000 AICD technology has been piloted in two new wells in two fields located in South Oman. The reservoir contains viscous oil (400-600 cp) and exhibits high inflow potential due to favourable rock properties and strong bottom water aquifer. Horizontal wells have been used to maximize reservoir oil contact and improve recovery from the reservoir. The wells, in general, produce oil with very high water cut (>95%). Two horizontal wells were drilled recently, and each well was completed with AICDs along a completed lateral length of 500 m. The AICDs managed in bringing down the water cut to less than 5% from 95% observed in the surrounding wells. The production behaviour has been sustained for nearly a year now.\u0000 The success of the AICD trial has opened the doors for its wider use in reservoirs containing viscous oil. The AICD also has been tried in existing wells where it managed to reduce the gross and the water cut by 50% and increase the oil gain by 100%.\u0000 Plans are also in place to extend the AICD trials in existing wells and reap the benefits by maximising oil production while decreasing the unwanted water production.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"2012 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86430887","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Al-Sulaimani, Zainab Al-Rawahi, Conny Velazco Quesada, A. Anand, G. Hemink, M. Frumau, Azza Al-Hussaini, Muhammad Syed, Ruqaya Al-Zadjali, S. Mahajan, A. Al-Yahyai, M. Al-Mahrooqi, Jasim Ajmi
This paper summarizes the performance of a polymer flood pilot conducted in an unconsolidated sandstone reservoir in the South of the Sultanate of Oman with the objective of extending the envelope of polymer flood applications to lower permeability (average 100mD) and highly heterogeneous reservoirs. The water flood baseline phase performance was presented previously in paper SPE-188408 where the connectivity of the patterns together with injectivity were established prior to polymer injection. The main objectives of the pilot were to test ability to sustain injectivity of polymer into this particular reservoir, achieve sufficient water-cut reversal (10% or more), monitor polymer efficiency and evaluate operational impact on facilities due to sand production which was expected to increase with polymer flood. Several lab tests along with a previous polymer injectivity trial data were fed into the selection of the appropriate polymer and injection design for this reservoir type. The pilot pattern layout consisted of an inverted five spot with injector-producer spacing of 75m. The injector was equipped with fiber optics for data acquisition and real time surveillance. Polymer injection commenced in December 2017 using relatively low molecular weight HPAM3430. The plan was to inject polymer for a year and evaluate the performance for a potential field scale development. The fiber optics data acquisition has demonstrated clearly the injection conformance improvement during the switch from water injection to polymer. In addition, around 10% of incremental oil recovery was obtained with an average water cut reversal of 12% across the pattern where the total pattern recovery was over 30% (including the waterflood). In terms of sand production, no noticeable impact was found on the facilities from sand production due to the polymer. The pilot performance exceeded the pilot success criteria that were set prior to commencing the polymer injection in terms of water-cut reversal and incremental recovery over the waterflood and fall in line with the modeled high-end scenario.
{"title":"Successful Polymer Flood Pilot Application in Lower Permeability Heterogeneous Sandstone Reservoir in the South of the Sultanate of Oman","authors":"H. Al-Sulaimani, Zainab Al-Rawahi, Conny Velazco Quesada, A. Anand, G. Hemink, M. Frumau, Azza Al-Hussaini, Muhammad Syed, Ruqaya Al-Zadjali, S. Mahajan, A. Al-Yahyai, M. Al-Mahrooqi, Jasim Ajmi","doi":"10.2118/200051-ms","DOIUrl":"https://doi.org/10.2118/200051-ms","url":null,"abstract":"\u0000 This paper summarizes the performance of a polymer flood pilot conducted in an unconsolidated sandstone reservoir in the South of the Sultanate of Oman with the objective of extending the envelope of polymer flood applications to lower permeability (average 100mD) and highly heterogeneous reservoirs. The water flood baseline phase performance was presented previously in paper SPE-188408 where the connectivity of the patterns together with injectivity were established prior to polymer injection.\u0000 The main objectives of the pilot were to test ability to sustain injectivity of polymer into this particular reservoir, achieve sufficient water-cut reversal (10% or more), monitor polymer efficiency and evaluate operational impact on facilities due to sand production which was expected to increase with polymer flood.\u0000 Several lab tests along with a previous polymer injectivity trial data were fed into the selection of the appropriate polymer and injection design for this reservoir type. The pilot pattern layout consisted of an inverted five spot with injector-producer spacing of 75m. The injector was equipped with fiber optics for data acquisition and real time surveillance. Polymer injection commenced in December 2017 using relatively low molecular weight HPAM3430. The plan was to inject polymer for a year and evaluate the performance for a potential field scale development.\u0000 The fiber optics data acquisition has demonstrated clearly the injection conformance improvement during the switch from water injection to polymer. In addition, around 10% of incremental oil recovery was obtained with an average water cut reversal of 12% across the pattern where the total pattern recovery was over 30% (including the waterflood). In terms of sand production, no noticeable impact was found on the facilities from sand production due to the polymer. The pilot performance exceeded the pilot success criteria that were set prior to commencing the polymer injection in terms of water-cut reversal and incremental recovery over the waterflood and fall in line with the modeled high-end scenario.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84349305","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}
Daniel Wilson, Carla Morgan, Thu T. Nguyen, Nhut Nguyen
It is estimated that over 50% of the world's oil reserves are tied up in carbonate reservoirs. Predominantly, these reservoirs are oil wet in nature and as such, make sufficient primary and secondary recovery complex. Chemicals are considered as one of the more effective enhanced oil recovery (EOR) sources, but are often complicated by temperature and salinity parameters. Extended carboxylate surfactants have been proven to be effective molecules to positively interact with crude oil at higher reservoir extremes. In this study, adsorption of alkyl ether carboxylate extended surfactants were evaluated at elevated temperature and constant salinity using a limestone adsorbent media. Static adsorption is a commonly accepted laboratory technique used to help evaluate both technical and economic viability of surfactant based flooding applications in EOR processes. Various reports in literature suggest increases in salinity and temperature may increase adsorption tendencies. Focus was placed here on how various extensions of propylene oxide (PO) and/or ethylene oxide (EO) may influence carboxylate surfactant adsorption data. Results are intended to reveal how augmentations in hydrophilic-lipophilic balance (HLB) may either positively or negatively affect surfactant loss using static adsorption at elevated temperature. Several different alkyl ether carboxylate surfactants were studied. The academic focus for this effort was placed more on surfactant parameters being evaluated, with regard to carbonate rock mineralogy at high temperature, to study surfactant adsorption behaviour without interference of other influences. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the overall complexity of this phenomenon. Experimental results found in this study show that various surfactant extensions affect adsorption differently. An increase in some hydrophobic properties appear to increase surfactant adsorption. This was observed through a couple different mechanisms including increasing percent ratio of PO to EO, or increasing molecular weight of the surfactants. Conversely, increasing carbon chain length and increasing degree of alcohol branching appeared to show a general decrease in adsorption trend versus limestone mineralogy, as well as higher percent of EO. It was also observed that ratios of PO and EO extensions will also have a variable influence on surfactant adsorption. Defining experiments in the laboratory can improve overall economic efficiency of surfactant based chemical EOR processes in the field, which often struggle due to loss of chemicals by adsorption to the reservoir rock. Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. Findings from this study will be used to improve understanding on how the role of various extensions on carboxylate s
{"title":"Adsorption Study of Extended Carboxylate Surfactants for High Temperature Carbonate Reservoir Enhanced Oil Recovery","authors":"Daniel Wilson, Carla Morgan, Thu T. Nguyen, Nhut Nguyen","doi":"10.2118/200070-ms","DOIUrl":"https://doi.org/10.2118/200070-ms","url":null,"abstract":"\u0000 It is estimated that over 50% of the world's oil reserves are tied up in carbonate reservoirs. Predominantly, these reservoirs are oil wet in nature and as such, make sufficient primary and secondary recovery complex. Chemicals are considered as one of the more effective enhanced oil recovery (EOR) sources, but are often complicated by temperature and salinity parameters. Extended carboxylate surfactants have been proven to be effective molecules to positively interact with crude oil at higher reservoir extremes.\u0000 In this study, adsorption of alkyl ether carboxylate extended surfactants were evaluated at elevated temperature and constant salinity using a limestone adsorbent media. Static adsorption is a commonly accepted laboratory technique used to help evaluate both technical and economic viability of surfactant based flooding applications in EOR processes. Various reports in literature suggest increases in salinity and temperature may increase adsorption tendencies. Focus was placed here on how various extensions of propylene oxide (PO) and/or ethylene oxide (EO) may influence carboxylate surfactant adsorption data. Results are intended to reveal how augmentations in hydrophilic-lipophilic balance (HLB) may either positively or negatively affect surfactant loss using static adsorption at elevated temperature.\u0000 Several different alkyl ether carboxylate surfactants were studied. The academic focus for this effort was placed more on surfactant parameters being evaluated, with regard to carbonate rock mineralogy at high temperature, to study surfactant adsorption behaviour without interference of other influences. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the overall complexity of this phenomenon. Experimental results found in this study show that various surfactant extensions affect adsorption differently. An increase in some hydrophobic properties appear to increase surfactant adsorption. This was observed through a couple different mechanisms including increasing percent ratio of PO to EO, or increasing molecular weight of the surfactants. Conversely, increasing carbon chain length and increasing degree of alcohol branching appeared to show a general decrease in adsorption trend versus limestone mineralogy, as well as higher percent of EO. It was also observed that ratios of PO and EO extensions will also have a variable influence on surfactant adsorption.\u0000 Defining experiments in the laboratory can improve overall economic efficiency of surfactant based chemical EOR processes in the field, which often struggle due to loss of chemicals by adsorption to the reservoir rock.\u0000 Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. Findings from this study will be used to improve understanding on how the role of various extensions on carboxylate s","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"434 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85533901","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 complete lifecycle of Safety Instrumented Functions (SIFs) in process industry should be well managed to achieve the right level of risk reduction. The lifecycle phases in accordance to IEC60511 can be broadly divided in to Analysis, Realization and Operation. Normally, the main focus is on the Analysis phase wherein Safety Integrity Levels(SILs) are determined, Probability of Failure on Demand (PFD) is calculated to arrive at the optimum design, and Safety Requirement Specification is developed for detailed design. However, the rest of the phases in the lifecycle are not addressed with the same vigor. The lesser attention given to later phases of safety lifecycle worsen the PFD calculated in design phase and keeps safety systems vulnerable to failures. When failures become certain, incidents happen and can lead to catastrophic effects. During a vessel level high-high (LZHH) demand in PDO, the inlet valves (two in series) failed to close leading to carry over of liquid hydrocarbon to the flare stack that led to liquid release from flare in a form of fire balls. The incident investigation revealed that even though required risk reduction levels were achieved in design by installing two valves in series, the rest of the Safety Instrumentation lifecycle phases were not rigorously adhered to resulting in the incident. In this paper the Authors endeavor to present various actions taken by PDO in order to make sure that what is designed, is operated and maintained as intended and in the process fulfilling the SIF lifecycle requirements.
{"title":"Incident Learning: Addressing the Functional Safety Life Cycle Requirements in PDO","authors":"Palaniappan Kannan, Abdul Aziz Abri","doi":"10.2118/200118-ms","DOIUrl":"https://doi.org/10.2118/200118-ms","url":null,"abstract":"\u0000 The complete lifecycle of Safety Instrumented Functions (SIFs) in process industry should be well managed to achieve the right level of risk reduction. The lifecycle phases in accordance to IEC60511 can be broadly divided in to Analysis, Realization and Operation. Normally, the main focus is on the Analysis phase wherein Safety Integrity Levels(SILs) are determined, Probability of Failure on Demand (PFD) is calculated to arrive at the optimum design, and Safety Requirement Specification is developed for detailed design. However, the rest of the phases in the lifecycle are not addressed with the same vigor. The lesser attention given to later phases of safety lifecycle worsen the PFD calculated in design phase and keeps safety systems vulnerable to failures. When failures become certain, incidents happen and can lead to catastrophic effects.\u0000 During a vessel level high-high (LZHH) demand in PDO, the inlet valves (two in series) failed to close leading to carry over of liquid hydrocarbon to the flare stack that led to liquid release from flare in a form of fire balls. The incident investigation revealed that even though required risk reduction levels were achieved in design by installing two valves in series, the rest of the Safety Instrumentation lifecycle phases were not rigorously adhered to resulting in the incident. In this paper the Authors endeavor to present various actions taken by PDO in order to make sure that what is designed, is operated and maintained as intended and in the process fulfilling the SIF lifecycle requirements.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84981796","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}
Muhannad Awadalla, Ramiro Oswaldo, Vasquez Bautista, Ahmed El Hawy, A. Beche, Ahmed Elkarim, Ghaida Abdullah Salim Al Ghaithi, Assad Al Maktomi, Vanessa Carolina Sanchez Gonzalez, Hussain Al Rashdi, Hafidh Al Nummani, Hashemi Al-Khalil, Shatha Omairi
Ultralow-resistivity reservoirs, common in Oman, are frequently encountered when drilling wells at the flank of an infill field with nearby oil/water contacts (OWC) in a reservoir sweet spot window of 1 to 2- m true stratigraphycal thickness (TST). An integrated solution developed to better position the wells in this type of reservoir has resulted in successful cases on net-to-gross (NTG), which exceeded expectations in terms of wells production and well deliveries. Integrating resistivity propagation curves response with directional resistivity curves (distance- to- boundary curves) response allows for optimizing well placement and assists in determining the best approach of well objective during drilling. Once drilling the lateral section began, a careful evaluation of the distance-to-boundary service tool inversion and directional measurements were performed in addition to conventional resistivity curves evaluation. This procedure ensured accurate placement of the well; thereby, avoiding water contact. Drilling optimization in long lateral sections has been carried out by optimizing bottom hole assembly (BHA) design, bit selection, and drilling parameters, taking geo-mechanics and geological uncertainty factors into consideration.
{"title":"Drilling Optimization in the Low-Resistive, Thin-Layer Reservoirs of Northern Oman","authors":"Muhannad Awadalla, Ramiro Oswaldo, Vasquez Bautista, Ahmed El Hawy, A. Beche, Ahmed Elkarim, Ghaida Abdullah Salim Al Ghaithi, Assad Al Maktomi, Vanessa Carolina Sanchez Gonzalez, Hussain Al Rashdi, Hafidh Al Nummani, Hashemi Al-Khalil, Shatha Omairi","doi":"10.2118/200259-ms","DOIUrl":"https://doi.org/10.2118/200259-ms","url":null,"abstract":"\u0000 Ultralow-resistivity reservoirs, common in Oman, are frequently encountered when drilling wells at the flank of an infill field with nearby oil/water contacts (OWC) in a reservoir sweet spot window of 1 to 2- m true stratigraphycal thickness (TST). An integrated solution developed to better position the wells in this type of reservoir has resulted in successful cases on net-to-gross (NTG), which exceeded expectations in terms of wells production and well deliveries.\u0000 Integrating resistivity propagation curves response with directional resistivity curves (distance- to- boundary curves) response allows for optimizing well placement and assists in determining the best approach of well objective during drilling. Once drilling the lateral section began, a careful evaluation of the distance-to-boundary service tool inversion and directional measurements were performed in addition to conventional resistivity curves evaluation. This procedure ensured accurate placement of the well; thereby, avoiding water contact.\u0000 Drilling optimization in long lateral sections has been carried out by optimizing bottom hole assembly (BHA) design, bit selection, and drilling parameters, taking geo-mechanics and geological uncertainty factors into consideration.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83693499","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}
Mohammad Reza Heidari Varnamkhasti, Qasim Al Hinaai, Ravindra Patil, Ali Baqir Al Lawati, Rashid Al Ghasani, Ramiro Oswaldo Vasquez Bautista
This paper presents a deep horizontal drilling campaign with the goal of eliminating several inefficiencies restricting the drilling performance, including downhole drilling bit or tool failures. The operator and the service company identified the inefficiencies by using engineering methods to overcome the challenges. Since 2013, the operator had been drilling horizontal wells with 600 to 1000 m of lateral targeting deep gas sandstone multilayer reservoirs with 15 to 35 kpsi unconfined compressive strength. The focus in the campaign will be from the kickoff point in the 8 3/8-in. section to the total depth (TD) of the well. Well-1 performance was greatly affected by the issues related to the wellbore instability in the build section, which dictated a change in the well program from the original fat to slim design. Later, other challenges and drilling inefficiencies resulted from this change, causing Well-6 design to be switched back to the original fat design to improve wellbore stability by having proper mud weight and other mud properties, bit and drive systems selection, as well as the drilling practices. Mechanical specific energy (MSE) is an industry recognized optimization tool to evaluate the drilling efficiency (Teale 1965) but it does not identify the sources of the inefficiencies (Chen 2019). The MSE, in addition to the downhole high-resolution drilling dynamics data, have been used to identify not only the drilling dysfunctions but also to help find the sources. This method supports the decisions for a change in the well design, bit, or the drilling practices, which in turn reduces the total number of runs and the downhole tool failures or damages. The improvements in drilling the horizontal wells since the campaign began are significant; i.e., Well-1 was drilled in approximately 165 days in 2014 while Well-6 was drilled in 49 days in 2017, which was 39 days ahead of the well plan with the majority improvements occurring in the last section. Well-6 is considered to be the most efficient Barik formation horizontal well drilled in Oman to date.
{"title":"Hard Rock Horizontal Drilling—Using Mechanical Specific Energy, Downhole Vibrations Analysis, and Well Design to Optimize Performance","authors":"Mohammad Reza Heidari Varnamkhasti, Qasim Al Hinaai, Ravindra Patil, Ali Baqir Al Lawati, Rashid Al Ghasani, Ramiro Oswaldo Vasquez Bautista","doi":"10.2118/200262-ms","DOIUrl":"https://doi.org/10.2118/200262-ms","url":null,"abstract":"\u0000 This paper presents a deep horizontal drilling campaign with the goal of eliminating several inefficiencies restricting the drilling performance, including downhole drilling bit or tool failures. The operator and the service company identified the inefficiencies by using engineering methods to overcome the challenges. Since 2013, the operator had been drilling horizontal wells with 600 to 1000 m of lateral targeting deep gas sandstone multilayer reservoirs with 15 to 35 kpsi unconfined compressive strength. The focus in the campaign will be from the kickoff point in the 8 3/8-in. section to the total depth (TD) of the well. Well-1 performance was greatly affected by the issues related to the wellbore instability in the build section, which dictated a change in the well program from the original fat to slim design. Later, other challenges and drilling inefficiencies resulted from this change, causing Well-6 design to be switched back to the original fat design to improve wellbore stability by having proper mud weight and other mud properties, bit and drive systems selection, as well as the drilling practices. Mechanical specific energy (MSE) is an industry recognized optimization tool to evaluate the drilling efficiency (Teale 1965) but it does not identify the sources of the inefficiencies (Chen 2019). The MSE, in addition to the downhole high-resolution drilling dynamics data, have been used to identify not only the drilling dysfunctions but also to help find the sources. This method supports the decisions for a change in the well design, bit, or the drilling practices, which in turn reduces the total number of runs and the downhole tool failures or damages.\u0000 The improvements in drilling the horizontal wells since the campaign began are significant; i.e., Well-1 was drilled in approximately 165 days in 2014 while Well-6 was drilled in 49 days in 2017, which was 39 days ahead of the well plan with the majority improvements occurring in the last section. Well-6 is considered to be the most efficient Barik formation horizontal well drilled in Oman to date.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75105823","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}
T. Skauge, P. A. Ormehaug, A. Alsumaiti, S. Masalmeh, A. Skauge
Polymer flooding has a large potential for unlocking EOR reserves in carbonate reservoirs in the Middle East. ADNOC has developed an EOR roadmap to realize some of these reserves. A milestone on this roadmap is to identify and verify polymers that have good performance at high temperature and high salinity conditions. The reservoir conditions include temperatures in the range of 100 – 130 ºC and formation brines of more than 200 000 ppm TDS with high concentrations of divalent ions in carbonate rock. These conditions have been beyond the limitations of synthetic polymers and most biopolymers. Here we report thermal stability measurements performed at anaerobic conditions for a number of synthetic polymers at high temperature, high salinity (HTHS) conditions. A custom thermal stability chamber and flooding rig was designed and produced where storage and measurements were performed without contact with oxygen or iron. A series of synthetic polymers with different ratios of the monomers amide, acrylate, ATBS and NVP were tested for temperature stability for up to 2 years at 120 ºC. Shear viscosity was measured frequently from the start while the time between tests was increased after trends in viscosity versus temperature was established. The viscosity was determined by measuring the differential pressure over a long coiled tubing. Three different brines ranging from ~200 to ~180 000 mg/L TDS were used as solvents. The results show that polymers with a low degree of ATBS and/or NVP have poor stability at the combined conditions of high temperature and high salinity and degrade within a short time. Polymers with a high degree of ATBS showed good stability at HTHS conditions. For these polymers high salinity improved stability, probably by stabilizing polymer conformation. In this paper, we report thermal stability at HTHS conditions for a number of polymers using a custom designed thermal stability chamber and flooding rig for storage and viscosity measurement. The design gives significant improvement over other methods where samples are either removed and exposed to air during measurement or opened to inert atmosphere during measurement. Polymers stable at HTHS conditions were identified, expanding the boundaries for polymer EOR applications to carbonate reservoirs with temperatures up to 120 ºC and high salinity formation water.
{"title":"Polymer Stability at Harsh Temperature and Salinity Conditions","authors":"T. Skauge, P. A. Ormehaug, A. Alsumaiti, S. Masalmeh, A. Skauge","doi":"10.2118/200178-ms","DOIUrl":"https://doi.org/10.2118/200178-ms","url":null,"abstract":"\u0000 Polymer flooding has a large potential for unlocking EOR reserves in carbonate reservoirs in the Middle East. ADNOC has developed an EOR roadmap to realize some of these reserves. A milestone on this roadmap is to identify and verify polymers that have good performance at high temperature and high salinity conditions.\u0000 The reservoir conditions include temperatures in the range of 100 – 130 ºC and formation brines of more than 200 000 ppm TDS with high concentrations of divalent ions in carbonate rock. These conditions have been beyond the limitations of synthetic polymers and most biopolymers. Here we report thermal stability measurements performed at anaerobic conditions for a number of synthetic polymers at high temperature, high salinity (HTHS) conditions. A custom thermal stability chamber and flooding rig was designed and produced where storage and measurements were performed without contact with oxygen or iron.\u0000 A series of synthetic polymers with different ratios of the monomers amide, acrylate, ATBS and NVP were tested for temperature stability for up to 2 years at 120 ºC. Shear viscosity was measured frequently from the start while the time between tests was increased after trends in viscosity versus temperature was established. The viscosity was determined by measuring the differential pressure over a long coiled tubing. Three different brines ranging from ~200 to ~180 000 mg/L TDS were used as solvents. The results show that polymers with a low degree of ATBS and/or NVP have poor stability at the combined conditions of high temperature and high salinity and degrade within a short time. Polymers with a high degree of ATBS showed good stability at HTHS conditions. For these polymers high salinity improved stability, probably by stabilizing polymer conformation.\u0000 In this paper, we report thermal stability at HTHS conditions for a number of polymers using a custom designed thermal stability chamber and flooding rig for storage and viscosity measurement. The design gives significant improvement over other methods where samples are either removed and exposed to air during measurement or opened to inert atmosphere during measurement. Polymers stable at HTHS conditions were identified, expanding the boundaries for polymer EOR applications to carbonate reservoirs with temperatures up to 120 ºC and high salinity formation water.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80758354","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Hoy, Timur Cimitoglu, P. Knauhs, D. Steineder, M. Sieberer, M. Kornberger, Oystein Molstre
OMV Austria E&P GmbH operates 26 oil fields in Lower Austria. The majority was developed in the 1950s and 1960s and shows an extended decline period. The challenge of operating brown fields is seen to maintain a reasonable oil production over time in a cost effective manner - this can be tackled by a major chemical enhanced oil recovery field redevelopment project. The scope of the polymer field rollout is to create and efficiently operate horizontal polymer injection patterns in two horizons in Lower Austria. OMV follows the strategy to pilot new reservoir and production technologies before their application in field rollouts. Due to the large project investment volume it is crucial to derive information and lessons learned from existing pilot patterns to optimize conceptual decisions on artificial lift, completion, sand control and injection strategy and to reduce technical risk. In the past 10 years several vertical pilot patterns were created to analyze the efficacy of polymer injection in the Tortonian Horizon. Significant operational experience in water treatment, polymer injection and polymer back production, but also in tracer testing was established. Since already the vertical polymer patterns showed not only operational success, but also significant incremental oil production, the idea of horizontal flooding patterns was born. To confirm and understand the impact of polymer injection also in horizontal wells, a first horizontal pilot pattern was drilled; additional pilot wells are currently following. For a future field redevelopment the technology selection should be de facto based on either standard or pilot-proven technologies. This paper describes measures undertaken in the discipline of production technology to prepare for one of the largest field redevelopment projects in the history of OMV Austria. These measures include the application of several pilot projects in the field of artificial lift, completion design and sand control, production and injection allocation. Therewith production technology serves the needs for active reservoir management and thus, follows a holistic field development approach.
OMV Austria E&P GmbH在下奥地利州经营26个油田。大多数是在20世纪50年代和60年代发展起来的，并呈现出长期的衰退期。棕地开发面临的挑战是如何在一段时间内以经济有效的方式保持合理的石油产量，这可以通过一个大型的化学提高采收率油田重建项目来解决。聚合物油田的推广范围是在下奥地利州的两个层位创建并有效地运行水平聚合物注入模式。OMV遵循的策略是，在新油藏和生产技术应用于现场之前，先进行试验。由于项目投资额巨大，因此从现有的试验模式中获取信息和经验教训，以优化人工举升、完井、防砂和注入策略的概念决策，并降低技术风险至关重要。在过去的10年里，人们创建了几种垂直先导模式来分析Tortonian地层中聚合物注入的效果。在水处理、聚合物注入和聚合物回采以及示踪剂测试方面积累了丰富的操作经验。由于垂直聚合物模式不仅在作业上取得了成功，而且还显著增加了石油产量，因此水平驱模式的想法应运而生。为了确认和了解聚合物注入对水平井的影响，我们钻了第一个水平先导井;目前正在进行更多的试验井。对于未来的油田再开发，技术选择实际上应该基于标准或试点验证的技术。本文描述了在生产技术方面所采取的措施，为奥地利OMV公司历史上最大的油田再开发项目之一做准备。这些措施包括在人工举升、完井设计和防砂、生产和注入分配等领域的几个试点项目的应用。因此，生产技术满足了主动油藏管理的需要，因此遵循了整体油田开发方法。
{"title":"Production Technology Selection for an EOR Redevelopment Project – Lessons Learned from Polymer Pilots","authors":"M. Hoy, Timur Cimitoglu, P. Knauhs, D. Steineder, M. Sieberer, M. Kornberger, Oystein Molstre","doi":"10.2118/200290-ms","DOIUrl":"https://doi.org/10.2118/200290-ms","url":null,"abstract":"\u0000 OMV Austria E&P GmbH operates 26 oil fields in Lower Austria. The majority was developed in the 1950s and 1960s and shows an extended decline period. The challenge of operating brown fields is seen to maintain a reasonable oil production over time in a cost effective manner - this can be tackled by a major chemical enhanced oil recovery field redevelopment project. The scope of the polymer field rollout is to create and efficiently operate horizontal polymer injection patterns in two horizons in Lower Austria.\u0000 OMV follows the strategy to pilot new reservoir and production technologies before their application in field rollouts. Due to the large project investment volume it is crucial to derive information and lessons learned from existing pilot patterns to optimize conceptual decisions on artificial lift, completion, sand control and injection strategy and to reduce technical risk.\u0000 In the past 10 years several vertical pilot patterns were created to analyze the efficacy of polymer injection in the Tortonian Horizon. Significant operational experience in water treatment, polymer injection and polymer back production, but also in tracer testing was established.\u0000 Since already the vertical polymer patterns showed not only operational success, but also significant incremental oil production, the idea of horizontal flooding patterns was born. To confirm and understand the impact of polymer injection also in horizontal wells, a first horizontal pilot pattern was drilled; additional pilot wells are currently following. For a future field redevelopment the technology selection should be de facto based on either standard or pilot-proven technologies.\u0000 This paper describes measures undertaken in the discipline of production technology to prepare for one of the largest field redevelopment projects in the history of OMV Austria. These measures include the application of several pilot projects in the field of artificial lift, completion design and sand control, production and injection allocation. Therewith production technology serves the needs for active reservoir management and thus, follows a holistic field development approach.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80441075","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}
Sufyan Shihab, Shaikhan Khadhuri, Hamoud Saadi, H. Aakre, V. Mathiesen
Managing increasing volumes of produced water is one of the main challenges faced in waterflood fields. Better water mobility -compared to oil-, results in increasing water cut (WC) and reduced oil production, with time. In Qarn Alam, with mature brown fields depleted through waterflooding, oil producers are completed as open-hole horizontal wells. This means well experience water breakthrough from day one, due to poor oil-to-water mobility ratio, toe-heel effect, permeability variations and matrix fractures. Inflow Control Devices (ICD) has demonstrated good efficiency in delaying water breakthrough, however, when breakthrough is a given factor, ICDs lose that efficiency. The Autonomous Inflow Control Valve (AICV®) is a novel powerful tool that helps reducing WC in favour of oil, based on contrasts in fluid viscosities. The tool has a movable piston that opens/closes autonomously -without any connection to surface-, to reduce the unwanted water production, where choking increases with increasing WC. AICV technology was deployed in several oil producers, in carbonate reservoir brown field. The field has produced for decades, and is facing an increasing water management challenge. AICV completions were designed such that wells are divided into compartments isolated by swellable packers. The comparison of historical production data without and with autonomous inflow shows clearly the benefit of installing autonomous inflow control. Preliminary assessment showed an average 75% reduction in water-cut and 20% average increase in oil rate.
{"title":"Optimising Waterflood Performance in Mature Fields, Using Autonomous Inflow Control Valve Technology","authors":"Sufyan Shihab, Shaikhan Khadhuri, Hamoud Saadi, H. Aakre, V. Mathiesen","doi":"10.2118/200171-ms","DOIUrl":"https://doi.org/10.2118/200171-ms","url":null,"abstract":"\u0000 Managing increasing volumes of produced water is one of the main challenges faced in waterflood fields. Better water mobility -compared to oil-, results in increasing water cut (WC) and reduced oil production, with time. In Qarn Alam, with mature brown fields depleted through waterflooding, oil producers are completed as open-hole horizontal wells. This means well experience water breakthrough from day one, due to poor oil-to-water mobility ratio, toe-heel effect, permeability variations and matrix fractures. Inflow Control Devices (ICD) has demonstrated good efficiency in delaying water breakthrough, however, when breakthrough is a given factor, ICDs lose that efficiency. The Autonomous Inflow Control Valve (AICV®) is a novel powerful tool that helps reducing WC in favour of oil, based on contrasts in fluid viscosities. The tool has a movable piston that opens/closes autonomously -without any connection to surface-, to reduce the unwanted water production, where choking increases with increasing WC. AICV technology was deployed in several oil producers, in carbonate reservoir brown field. The field has produced for decades, and is facing an increasing water management challenge. AICV completions were designed such that wells are divided into compartments isolated by swellable packers. The comparison of historical production data without and with autonomous inflow shows clearly the benefit of installing autonomous inflow control. Preliminary assessment showed an average 75% reduction in water-cut and 20% average increase in oil rate.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"113 ( Pt 1) 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78850358","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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