lateral

Abstract The deep carbonate reservoir formation on this field has proven to be an extreme High-temperature (HT) environment for downhole equipment. While drilling the 5000 - 6500 ft 5-7/8" slim long laterals across this formation, very high bottom-hole circulating temperatures is encountered (310-340 degF) which exceeds the operating limitation for the downhole drilling/formation evaluation tools. This resulted in multiple temperature-related failures, unplanned trips and long non-productive-time. It became necessary to provide solution to reduce the BHCT-related failures. Performed offset-wells-analysis to identify the BHT regime across the entire-field, create a heat-map and correlate/compare actual formation-temperatures with the formation-temperature-gradient provided by the operator (1.4-1.8 degF/100-ft). Drilling reports and MWD/LWD/wireline logs were reviewed/analyzed. Reviewed tools-spec-sheets, discovered most of the tools had a maximum-temperature-rating of 300-302 degF and were run outside-technical-limits. Observed temperature-related-failures were predominant in very long slim-laterals, which indicated that some of the heat was generated by high flow rate/RPM and solids in the system. Tried drilling with low-RPM/FR, did not achieve meaningful-temperature-reduction. After detailed risk-assessment and analysis on other contributing factors in the drilling process, opted to incorporate mud-chiller into the surface circulating-system to cool-down the mud going into the well. Upon implementation of the mud chiller system, observed up to 40 degF reduction in surface temperature (i.e. temperature-difference between the mud entering/leaving mud chiller). This was achieved because the unit was set-up to process at least twice the rate that was pumped downhole. Also observed reduction in the bottom-hole circulating temperature to below 300 degF, thus ensuring the drilling environment met the tool specifications. The temperature-related tools failure got eliminated. On some of the previous wells, wireline logging tools have been damaged due to high encountered downhole temperature as circulation was not possible prior-to or during logging operation. The implementation of the mud-chiller system has made it possible for innovative logging thru-bit logging application to be implemented. This allows circulation of cool mud across the entire open hole prior to deployment of tools to perform logging operation. This has made it possible for same logging tool to be used for multiple jobs without fear of tool electronic-components failure die to exposure to extreme temperatures. The long non-productive time due to temperature-related tool failures got eliminated. The numerous stuck pipes events due to hole deterioration resulting from multiple round trips also got eliminated. Overall drilling operations became more efficient. The paper will describe the drilling challenges, the systematic approach implemented to arrive at optimized solution. It will show how good understanding of drilling challenges and tailored-solutions delivers great gains. The authors will show how this system was used to provide a true step-change in performance in this challenging environment.

OnePetro

doi: 10.2118/214623-MS

SPE

SPE-214623-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

Country:

Europe > United Kingdom (0.46)
North America > United States > Texas (0.28)
Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.15)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

Technology: Information Technology (0.68)

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Successful Sidetrack in Challenging Formation Resulted in CAPEX Reduction

Al-Raml, Haidar (Saudi Aramco) | Ufondu, Kenechukwu (Saudi Aramco) | Widjaja, Danang (Saudi Aramco) | Almasri, Abdulrakeeb (Halliburton Saudi)

OnePetroMay, 2023

Abstract This paper discusses the added value of a new approach to exiting an existing wellbore, where the normal practice forces the plug and abandonment (P&A) of the existing lateral before cutting the window into a new lateral, particularly when an off-bottom cemented (OBC) liner is required. The new approach includes the construction of a Technology Advancement of Multilaterals Level 4 (TAML 4) junction to maintain well integrity and the successful development of a re-entry window that allows access to both the existing and the new slim wells. Not only has this technique unlocked massive potential, but it has also led to an enhancement in the utility and reduction in capital expenditure (CAPEX). The successful Level 4 sidetrack and re-entry window deployment is directly related to the robust system design. The application developed includes an anchor with a guide and high-torque capability, a TAML Level 4 junction created in a shape that will lead to smooth, repeatable access in the future, and a customized re-entry window system to further maximize the well potential. The true value is in allowing access to both the existing and the newly drilled lateral without using a rig or decompleting the well. Such operations use tubing exit whipstock (TEW) and pressure isolation sleeves, both of which can be run and retrieved in a rigless manner. The rigless access has allowed the existing lateral to be used as an observation well. Using permanent downhole gauges (PDHGs) enables real-time monitoring of the pressure and temperature and periodic logging to evaluate the reservoir. The newly drilled lateral can be the primary producing lateral; rigless access equally helps recover the well in case of any production challenges. The newly designed multilateral is a game changer for both mature and new developments because it maximizes reservoir production and helps reduce CAPEX by requiring fewer wells to be drilled. The improved well integrity minimizes well workover operations, which creates cost savings. This paper discusses the following aspects:A successful Level 4 junction construction from a slim re-entry existing/mature well. Repeatable accessibility to the lateral and motherbore. Meeting the motherbore objective as required. Delivering an OBC lateral liner and maintaining the well integrity.

OnePetro

doi: 10.2118/214627-MS

SPE

SPE-214627-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

Country: Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.15)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Well Completion (1.00)
Production and Well Operations (1.00)

Technology: Information Technology > Architecture > Real Time Systems (0.54)

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Abstract Extended reach drilling (ERD) can facilitate the development of untapped resources, reduce greenhouse gas emissions, surface congestion, and drilling costs. This ERD project with lower completion was started with an aim to lower well cost indicators including $/ft and $/bbl. Therefore, the challenge was to drill Slimhole ERD (6-1/8″ lateral) wells with water-based mud (WBM). WBM is more cost-effective, environmentally friendly, and less damaging to the reservoir than OBM (oil-based mud). The use of WBM instead of OBM can save $2MM per well. The major challenges in drilling Slimhole (6-1/8″ size) ERD well with lateral le include higher torque and failure to deploy lower completion due to high friction factors. The first pilot well was planned with a liner-less design considering the low friction factors required to drill 15,000′ of 6-1/8″ lateral hole and run the lower completion. The second pilot well was targeting a deeper and tighter reservoir zone with higher downhole temperatures. This involved drilling 12-1/4″ intermediate hole to the landing point with larger 5-1/2″ drill pipe. It enabled a push-pipe technique for drilling the lateral hole with improved weight transfer through the curved profile. The 6-1/8″ lateral hole was drilled with 4″ high-torque drill pipe, tandem high-flow circulating subs, and specially formulated drilling fluid lubricant. A conventional OBM system provides sufficient lubricity to reduce friction factors as low as 0.10. In this application, a low cost WBM system was made feasible by introducing stable high-temperature lubricant and unique hole cleaning practices. Following this successful achievement, the 5-year business plan has been revised to include 63 similar wells with a projected total savings of ~ $250MM. The Slimhole ERD project has demonstrated substantial value with a 35% reduction in CAPEX. The delivery of these two Slimhole ERD wells overturned conventional drilling and completion practices. The implemented project resulted in saving up to 35% of the well cost and saved 20 days per well compared to a conventional ERD well with 8-1/2″ hole and OBM. These two Slimhole ERD (15,000′ lateral) wells were drilled with a challenging Directional Difficulty Index (DDI) of 7.2. The wells were both completed successfully by running the 4-1/2″ lower completion to reach the total depth.

OnePetro

doi: 10.2118/214654-MS

SPE

SPE-214654-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

accumulation, asia government, centralizer, completion, cuttings, Directional Drilling, drilling operation, entry liner, international association, lateral, liner, packer, pipe, reservoir, slim hole erd well campaign, torque, uae government, Upstream Oil & Gas, water-based mud, WBM

Country: Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.50)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines: Well Drilling > Drilling Operations > Directional drilling (1.00)

Technology: Information Technology (0.47)

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Horizontal Well Design and Completion Optimization in the Greater Burgan Field for Heterogeneous Thin Sands, A Case Study

Al-Samhan, Amina (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Jilani, Syed Zeeshan (Schlumberger, Al-Ahmadi, Kuwait) | Al-Nemran, Shahad (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Muhammad, Yaser (Schlumberger, Al-Ahmadi, Kuwait)

OnePetroMay, 2023

Abstract The Greater Burgan field has been on production for over 75 years mainly from the homogenous massive sands of the Burgan clastic sequence. Given the increasing field water cut from these sands, it is now a matter of strategic focus for the asset to target the generally untapped thin, laminated low quality sands to sustain target production. This paper focuses on a case study for a horizontal well design and completion optimization using sector modeling. An updated dynamic model, covering the area of interest, was developed. This is an extremely important tool to achieve the study objectives. A sector model was cut out from the full field dynamic model. Grid refinement was performed on the sector, in both vertical and horizontal dimensions. Newly drilled wells were used to update the model horizons, petrophysical data from offset wells in the sector, including geosteering data from the pilot hole, were upscaled and properties populated across the model. The dynamic model calibration was conducted successfully by including all available well events, workovers, production data, static and flowing bottom hole and well head pressures including all other surveillance data from offset wells. To better match the historical field pressure and water-production, sensitivities were conducted to determine the model response to various parameters including the aquifer strength and faults conductivity. Adjustment of the aquifer strength enhanced the field pressure match, invariably improving the calibration of the model. After model calibration, the horizontal well was implemented in the model, in line with the design scope from the asset. The biggest uncertainty was the oil-water contact (OWC) in the sector near the planned well. Although offset wells gave a reasonable estimate of the OWC, it was used as sensitivity parameter to cover the uncertainty. This was taken forward into the model prediction simulation work. The modeling study provided immense insights into the probable outcomes in terms of actual horizontal well production deliverability. Multiple rate sensitivities were conducted mimicking the different choke sizes which were planned. These were used as a guide for the asset to set reasonable production target rates for the well. The study also provided a technical justification for completion recommendations and optimization with a view to maximizing the well's production over time. The horizontal well has been drilled, completed, and tested in the field. The production test rates were encouragingly consistent with the model predictions. The workflow methodologies adopted in this work have now been extended to other wells being drilled in the field.

OnePetro

doi: 10.2118/214590-MS

SPE

SPE-214590-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

asia government, completion optimization, Conference, Directional Drilling, drilling operation, greater burgan field, heterogeneous thin sand, Horizontal Well Design, hw1, icd, icd optimization case, Kuwait government, lateral, Modeling & Simulation, reservoir simulation, sensitivity, STBO, table 2, Upstream Oil & Gas

Country: Asia > Middle East > Kuwait > Ahmadi Governorate (1.00)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
(13 more...)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Reservoir Description and Dynamics > Reservoir Simulation (1.00)

Technology: Information Technology > Modeling & Simulation (0.47)

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Planning and Execution of First Underbalanced Coiled Tubing Drilling in Adnoc´s Fields Utilizing First Successful Closed Loop System Globally

OnePetroMay, 2023

Abstract The Operator planned and conducted Underbalanced Coiled Tubing Drilling (UBCTD), operations on 3 wells in Operator Onshore fields targeting tight sour gas carbonate reservoirs. The objectives of these operations were to evaluate the applicability of the technology in these fields, to understand requirements and methods of the technology and to evaluate the benefits of drilling the target formations in an underbalanced mode. As a preliminary step, the Operator conducted a feasibility study that flagged potential limitations to deploying UBCTD operations in existing wells, due to limitations on the completion design and other factors. All of this resulted in the plan to drill fit-for-purpose wells to the top of the reservoir to facilitate the deployment of the technique. These wells were completed with 5.5/4.5 in. Tubing and 7 in. Liner and left with a 100ft open hole interval from where CT drilling operations would later continue. The results of the feasibility study notwithstanding, additional detailed engineering work was performed in all aspects of the design by the operations team to ensure the success of the trial, including a review and validation of the available data and the feasibility to deliver the stated objectives (lateral length, underbalanced conditions, minimal flaring operations, drilling fluid re-circulation, etc.). As a result of this approach, all three wells were successfully drilled in underbalanced conditions and to the target lateral length of 4,000 ft. Well placement was facilitated using Biosteering techniques and continuous monitoring of the well performance vs. drilled footage, allowing steering decisions to be made in real-time to maximize the production of each lateral, resulting in outstanding production results of 3x the productivity of similar wells drilled conventionally, (after stimulation). This paper will detail the design process highlighting key engineering decisions and assumptions taken during the design process and comparing them to the actual behavior of the well and the impact of real-life constraints on the operational parameters. The base design and lessons learned from the project will serve as a launching pad for planning and efficiency gains for future UBCTD operations.

OnePetro

doi: 10.2118/214572-MS

SPE

SPE-214572-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

Country: Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.17)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.41)

SPE Disciplines:

Well Drilling > Pressure Management > Underbalanced drilling (1.00)
Well Drilling > Drilling Operations (1.00)
Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)

Technology: Information Technology (0.68)

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Evaluating Oil Quality and Microbial Activity Across Fault Blocks and Subunits of the Ugnu (N. Slope, Alaska) by Volatiles Analysis of Cuttings and Produced Crude - Implications for Completions and Production

Smith, Christopher M (Advanced Hydrocarbon Stratigraphy) | Nolan, Seth (Hilcorp Alaska, LLC) | Edwards, Reid (Hilcorp Alaska, LLC) | Conrad, Caleb (Baker Hughes) | Gordon, Patrick S (Advanced Hydrocarbon Stratigraphy) | Smith, Timothy M (Advanced Hydrocarbon Stratigraphy) | Smith, Michael P (Advanced Hydrocarbon Stratigraphy)

OnePetroMay, 2023

Abstract Hilcorp's Milne Point S-203 was drilled in 2019 targeting the biodegraded heavy oil of the Ugnu Formation, for exploration and development; being one of the first Ugnu wells to be successfully drilled, completed, and conventionally produced. S-203 crossed three fault blocks and intersected multiple Ugnu subunits. A volatiles analysis, via rock volatiles stratigraphy (RVS), of the cuttings from the main borehole and sidetracks enabled a spatial assessment of oil quantity, microbial activity, and the effect of faults in the different subunits. Produced oil from early in the life cycle of the well was analyzed with RVS, both RVS datasets were combined with completions to assess production contribution across the borehole. These results provide important insights for development of the Ugnu as a heavy oil play on the Alaskan North Slope.

OnePetro

doi: 10.2118/214494-MS

SPE

SPE-214494-MS

SPE Western Regional Meeting

Country: North America > United States > Alaska (0.16)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)

Oilfield Places:

Asia > Middle East > Turkey > Selmo Field > S-37 Well (0.99)
North America > United States > Wyoming > Wind River Basin (0.94)
North America > United States > Wyoming > Bighorn Basin (0.94)
(26 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Well Drilling > Drilling Measurement, Data Acquisition and Automation (0.94)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.69)
(2 more...)

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Data Driven Risk Analysis and Production Forecast Deration for Matrix Bypass Events in the West Sak Oil Pool, Alaska North Slope

Keith, Cody D (ConocoPhillips Alaska Inc.) | Abbas, Sayeed (ConocoPhillips Alaska Inc.) | Autry, Sydney (ConocoPhillips Alaska Inc.)

OnePetroMay, 2023

Abstract West Sak is a shallow viscous oil reservoir located partially within the Kuparuk River Unit on the North Slope of Alaska. The poorly consolidated reservoir is prone to sand production, leading to a significant risk for the development of void space conduits, locally known as matrix bypass events (MBEs). MBEs result in pattern breakage and lost production capacity, and this needs to be accounted for in production forecasting. In this study, a data-driven analysis is performed to identify factors that cause differential risk for MBE formation in each well. This analysis is then used to inform the creation of a tool that determines the expected production impacts of future MBEs and derates the forecast accordingly. The well patterns and MBE history in the West Sak reservoir are analyzed for differential risk based on sand geomechanics and producer/injector well completions. Specifically, the B sand was found to have the highest MBE risk due to its lower geomechanical strength, the D sand was found to have a significant yet lesser risk, and the A sand was found to have negligible risk. MBE risk is greater for patterns with horizontal production laterals without sand control and is negligible for horizontal producers with sand-exclusion screens or vertical producers. MBE risk is reduced when vertical injectors are used instead of horizontal injection laterals. This history is used to inform the development of MBE risk type curves based on the fatigue life distribution family of curves. These curves are used as input into an MBE deration forecasting tool, which produces a range of risk-informed MBE schedules. Based on each schedule, the tool "breaks" and "repairs" patterns accordingly, determining production losses based on allocation to each pattern. These individual production loss forecasts are then averaged to provide the expected outcome for forecast deration attributed to MBEs. The tool was successful in developing reasonable deration expectations on a well-by-well basis. The work done offers a probabilistic workflow to predict well downtime due to MBEs. Data-driven evidence is provided for factors that influence MBE risking, providing a means to capture expected production losses. This evidence proves to be consistent with physical models of this enigmatic phenomenon and informs future development opportunities to mitigate this risk. The approach pursued here can be applied to other known risks to production.

OnePetro

doi: 10.2118/212950-MS

SPE

SPE-212950-MS

SPE Western Regional Meeting

Country: North America > United States > Alaska > North Slope Borough (1.00)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places: North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Well Completion > Sand Control (1.00)
Reservoir Description and Dynamics > Reservoir Characterization (1.00)
(6 more...)

Technology: Information Technology > Artificial Intelligence > Machine Learning (0.93)

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Abstract Extended reach drilling (ERD) can facilitate the development of untapped resources, reduce greenhouse gas emissions, surface congestion, and drilling costs. This ERD project with lower completion was started with an aim to lower well cost indicators including $/ft and $/bbl. Therefore, the challenge was to drill Slimhole ERD (6-1/8″ lateral) wells with water-based mud (WBM). WBM is more cost-effective, environmentally friendly, and less damaging to the reservoir than OBM (oil-based mud). The use of WBM instead of OBM can save $2MM per well. The major challenges in drilling Slimhole (6-1/8″ size) ERD well with lateral le include higher torque and failure to deploy lower completion due to high friction factors. The first pilot well was planned with a liner-less design considering the low friction factors required to drill 15,000’ of 6-1/8″ lateral hole and run the lower completion. The second pilot well was targeting a deeper and tighter reservoir zone with higher downhole temperatures. This involved drilling 12-1/4″ intermediate hole to the landing point with larger 5-1/2″ drill pipe. It enabled a push-pipe technique for drilling the lateral hole with improved weight transfer through the curved profile. The 6-1/8″ lateral hole was drilled with 4″ high-torque drill pipe, tandem high-flow circulating subs, and specially formulated drilling fluid lubricant. A conventional OBM system provides sufficient lubricity to reduce friction factors as low as 0.10. In this application, a low cost WBM system was made feasible by introducing stable high-temperature lubricant and unique hole cleaning practices. Following this successful achievement, the 5-year business plan has been revised to include 63 similar wells with a projected total savings of ~ $250MM. The Slimhole ERD project has demonstrated substantial value with a 35% reduction in CAPEX. The delivery of these two Slimhole ERD wells overturned conventional drilling and completion practices. The implemented project resulted in saving up to 35% of the well cost and saved 20 days per well compared to a conventional ERD well with 8-1/2″ hole and OBM. These two Slimhole ERD (15,000’ lateral) wells were drilled with a challenging Directional Difficulty Index (DDI) of 7.2. The wells were both completed successfully by running the 4-1/2″ lower completion to reach the total depth.

OnePetro

doi: 10.4043/32266-MS

OTC

OTC-32266-MS

Offshore Technology Conference

Country: Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.40)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines: Well Drilling > Drilling Operations > Directional drilling (1.00)

Technology: Information Technology (0.47)

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Completion Diagnostic Tools, Production Logging Technology Delivers Accurate Flow Contributions Vertical & Horizontal Wellbores

Heddleston, Duncan Craig (Indepth Production Solutions)

OnePetroApril, 2023

Abstract Over the past 18 years, the industry has focused on drilling and completing horizontal producing wells, in order to develop better deliverability and UER across the reservoir. These types of wells are drilled with various inclinations, trajectories which porpoise across the reservoir interval. Horizontal lateral sections consist of numerous selectively stimulated stages containing greater than 20 stages spread out across 2,000 ft to 25,000 ft of horizontal interval. (Heddleston, 2017). Many indirect measurements such as chemical tracing or fiber optic sensing have been trialed, but the only direct measurement of real production contributing across a producing lateral is acquired using production logging measurements with production data analysis. This true measurement of production contribution is the best method which allow oil companies to understand and acknowledge which portions of the hydraulically stimulated reservoir is contributing the production and the value of their properties.

OnePetro

doi: 10.2118/213083-MS

SPE

SPE-213083-MS

SPE Oklahoma City Oil and Gas Symposium

Country: North America > United States > Oklahoma (0.16)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)

Technology: Information Technology > Communications > Networks (0.51)

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Abstract Horizontal drilling technologies have evolved during last decades making possible wells with thousands of feet of long horizontal sections. These drilling advancements have contributed to drill more intricate multilaterals wells to ensure a thorough contact with the reservoir. In terms of well accessibility for rig-based well interventions, these complex completion configurations add significant challenges. Upon drilling is completed, coiled tubing (CT) matrix acid stimulation is one of the first interventions used to remediate the formation damage and bring the well back on production. Operator in Kuwait drilled a level four six-legged multilateral well in the north area to maximize reservoir contact within lower and upper Tuba carbonate formations. This drilling approach enables several production schemes and versatility in the pursuit of economical production. As such, this completion approach required an advanced intervention technique that relied on CT optical telemetry and multilateral entry tool (MLT). Real-time downhole readings included casing collar locator (CCL), gamma ray, CT internal pressure, annulus pressure, annulus temperature, and axial force for accurate depth control, rapid lateral identification, optimal MLT actuation and understanding of dynamic downhole conditions along the operation. The level-four multilateral candidate had a six 6 1/8-in. uncased horizontal sections that needed cleanout from drilling oil-based mud (OBM) and matrix stimulation using an emulsified retarded acid system (ERAS) for enhanced wormholing into the carbonate rock. The lateral sections exhibited an average of 2,500 ft and the reservoir featured a bottomhole temperature near 130°F and bottomhole pressure close to 2,100 psi. By combining real-time optical telemetry with MLT, the profiling of three laterals was completed in less than 4 hours for each one, optimizing the rig time and the course of the treatment. Prior to the matrix stimulation, three laterals were conditioned via CT through a multifunctional solvent consisting of a synergistic blend of aromatic solvent and surfactants intended to breakdown and disperse OBM residuals without the need of mechanical agitation and also leaving the rock water wet. The three laterals were then acidized in a single run by pumping 450 bbl of multifunctional solvent followed by 1,500 bbl of ERAS. When compared to conventional CT intervention in multilateral wells, this enhanced intervention approach optimized the total intervention time by 33%, being fundamental the ability to make fast-informed decisions from optical telemetry. This paper documents a value case study for CT rig-based intervention in Kuwait, where combination of an array of technologies, such as CT optical telemetry, MLT, multifunctional solvent and ERAS, enabled cleanup and acidizing three laterals from six-legged multilateral wells in a single run. The lessons learned are now the reference for other operators in the Middle East for performing interventions in multilateral wells.

OnePetro

doi: 10.2118/212883-MS

SPE

SPE-212883-MS

SPE/ICoTA Well Intervention Conference and Exhibition

Country: Asia > Middle East > Kuwait (0.90)

Industry:

Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.99)
Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.99)
Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.99)
Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > SAMA Formation (0.99)

SPE Disciplines: Well Drilling > Drilling Operations > Directional drilling (1.00)

Technology: Information Technology > Architecture > Real Time Systems (0.90)

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Collaborating Authors

Managing High Bottom-Hole Temperature Challenges in Ultra-Slim Long Horizontal Wells

Successful Sidetrack in Challenging Formation Resulted in CAPEX Reduction

Longest Slim Hole ERD Wells Campaign with Limited Entry Liner Using Water-Based Mud in Onshore Abu Dhabi

Horizontal Well Design and Completion Optimization in the Greater Burgan Field for Heterogeneous Thin Sands, A Case Study

Planning and Execution of First Underbalanced Coiled Tubing Drilling in Adnoc´s Fields Utilizing First Successful Closed Loop System Globally

Evaluating Oil Quality and Microbial Activity Across Fault Blocks and Subunits of the Ugnu (N. Slope, Alaska) by Volatiles Analysis of Cuttings and Produced Crude - Implications for Completions and Production

Data Driven Risk Analysis and Production Forecast Deration for Matrix Bypass Events in the West Sak Oil Pool, Alaska North Slope

Longest Slim Hole ERD Wells Campaign with Limited Entry Liner Using Water-Based Mud In Onshore Abu Dhabi

Completion Diagnostic Tools, Production Logging Technology Delivers Accurate Flow Contributions Vertical & Horizontal Wellbores

Enhancing Rig-Based Intervention Efficiency in a Level Four - Six-Legged Multi-Lateral Oil Producer through Coiled Tubing Optical Telemetry, Multilateral Tool and Retarded Acid: A Case Study from North Kuwait Field

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