well-a

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.

doi: 10.2118/214627-MS

SPE/IADC Middle East Drilling Technology Conference and Exhibition

SPE-214627-MS

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)

World's Deepest Single-Trip Multistage Fracturing through 2-7/8-in. 7,400-m Coiled Tubing String: Method Development and Learnings from Norway

Abstract The Valhall and Hod chalk fields have seen the rise of single-trip multistage fracturing (STMF) that allows stimulating two to four zones in a single day in contrast to the average of one zone every 2 to 3 days for conventional applications. Recent advancements focus on lowering operational costs while bringing wells on production faster. One way of doing this is to further improve the STMF method by the introduction of fracturing through coiled tubing (FTCT). Conventional multistage fracturing operations use the plug-and-perforation method to complete each stage separately. With a sliding sleeve completion, coiled tubing (CT) is used to manipulate sleeves; then, proppants are pumped down the wellbore without CT in the well. Conversely, STMF uses a bottomhole assembly (BHA) with sleeve shifting tool and multiset packer for selective proppant stimulation down the CT-tubing annulus. Any underflush of proppants is cleaned by CT forward circulation. FTCT builds upon the STMF method, but proppants are pumped through CT. The underflush proppants are reverse circulated out of CT through a BHA without a check valve. FTCT was first used in a well at 5,000-m measured depth (MD) using a 6,700-m 2 7/8-in. CT. Data from this operation were used to match the friction calculation. In the second well at 6,500-m MD, intervened with a 7,400-m-long CT, 10 zones were stimulated using FTCT, and 2 zones with conventional fracturing. FTCT only required 8.5 hours whereas conventional fracturing took 75.6 hours per zone. The underflush volume was 50% less and removed through reverse cleanout that is 4 hours faster per stage compared to STMF. In the third well at 6,700-m MD, the well was killed with 1.35-SG heavy brine due to a leak in the completion. Proppant was pumped through CT and displaced with 1.04-SG brine. An increase in pumping pressure during reverse cleanout, compounded with the difference of fluid density, led to the collapse of CT section above the BHA. The collapse created difficulties for the BHA to unset, thus creating a mechanical sticking point, and hindered the ball drop release mechanism for the BHA. Awareness of pressure limitations of CT at the thinnest section is essential to improve the reverse cleanout design since high initial forces are required to reverse circulate. FTCT requires careful pressure analysis, especially when attempting operations in deep horizontal wells. Most standard CT cleanout simulation software lacks complete hydraulic modeling capabilities for reverse cleanout of crosslinked fluids with proppants. Data gathered from the three operations are thus important to improve the method. This study highlights associated challenges, considerations during design, operational benchmarks, and learnings from the world's longest FTCT operation in the North Sea.

doi: 10.2118/212902-MS

SPE/ICoTA Well Intervention Conference and Exhibition

SPE-212902-MS

Country: Europe > Norway > North Sea > Central North Sea (0.28)

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

Oilfield Places:

Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
(10 more...)

SPE Disciplines:

Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)

Technology: Information Technology (0.66)

Understanding Drilling Dynamics Thru Tandem Downhole Recording Tools Enabled Drilling Performance: Middle East Specific

AlHosni, Fahad (SLB) | Echevarria, Edgar (SLB) | Ruzhnikov, Alexey (SLB) | Rojas, Luis (SLB)

Abstract Drilling the 12.25-in. landing section in one of the Middle East fields had been a challenge in terms of drilling performance due to combined downhole severe drilling dynamic mechanics effects and borehole instabilities. These complications eventually lead to downhole tool failures and a low rate of penetration (ROP). This manuscript describes the solution to introduce tandem downhole dynamic recording tools in the Bottom Hole Assembly (BHA) which provides a better understanding of the downhole dynamics and mechanics effects guiding to optimum BHA design and leading to better performance. Drilling the curve and landing section is challenging due to extreme stick & slip (S&S) and shocks & vibrations (S&V) phenomena resulting in low performance and difficulties in achieving the directional requirement. The 12.25-in. landing section is drilled with a full set of Rotary Steerable System (RSS) drive, Positive Displacement Mud Motor (PDM), Measurement While Drilling (MWD) and Logging While Drilling (LWD) tools, making the BHA very rigid. Nevertheless, many initiatives have been carried out to enhance the BHA and bit design with limited improvement. After performing a detailed risk analysis, tandem downhole dynamic recording tools were introduced to understand the downhole dynamics behavior and the interaction between the bit, the drilling BHA components, and the different formations drilled. The downhole dynamic recording tool is powered by batteries and records the data in memory mode for post-run analysis. It measures downhole drilling mechanics with its three-axis accelerometers, gyro, and temperature electronics along with other measurements. The downhole recording tools was installed tandemly across the 12.25-in. motorized RSS BHA where one tool was positioned inside the bit and another one in a sub above the mud motor. After the run, all the data from the two downhole recording tools were downloaded and then analyzed. From the recording tool at the bit, it can be concluded that the PDC bit used in the analyzed run, generated low-to-medium stick & slip, hence, a new bit design with more aggressive features could be used safely to enhance the ROP. From the recording tool in the sub above the mud motor, it was concluded that the BHA components and mainly the LWD tool created high-to-severe stick & slip due to its stabilizers, and action should be taken to minimize this effect. In addition, the drilling fluid lubricity needs to be enhanced to reduce the stick & slip and shocks & vibrations effects on the tools. All the presented solutions and lessons learned of the downhole dynamic recording tools utilization can be used for future run enhancement and to be replicated worldwide as applicable.

doi: 10.2118/212801-MS

SPE Canadian Energy Technology Conference and Exhibition

SPE-212801-MS

Country:

North America > Canada (0.28)
Europe > Middle East (0.24)
Asia > Middle East (0.24)
Africa > Middle East (0.24)

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

SPE Disciplines:

Well Drilling > Drillstring Design > Drillstring dynamics (1.00)
Well Drilling > Drillstring Design > BHA design (1.00)
Well Drilling > Drilling Operations (1.00)
(3 more...)

Technology: Information Technology > Sensing and Signal Processing (0.87)

Ahmed, Sheraz (Pakistan Petroleum Limited) | Waqas, Ghulam Muhammad (Pakistan Petroleum Limited) | Sheikh, Hafiz Mustafa Ud Din (Pakistan Petroleum Limited)

An Innovative Approach to Revitalize a 70-Year-Old Mature Asset – A Case of Operational Excellence Coupled with Engineering Strategies

Abstract The E&P industry has been facing multitude of challenges including lack of large discoveries coupled with continuously declining production from existing assets. Moreover, the situation is aggravated due to large volumes of unproduced hydrocarbons at abandonment owing to unoptimized development strategies. This paper discusses the strategy adopted to revitalize declining production and target remainder of the sweet spots in a mature gas field on production for the last seven decades. Furthermore, the workflow introduced, integrates the surface and subsurface engineering strategies with an ideal blend of operational considerations that avoids heavy CAPEX involvement. The field presented in this paper has been producing since 1955, with around 112 wells in four independent reservoirs. Three of these reservoirs are fractured limestone with more than 80% depletion (with very little to moderate aquifer support). At its plateau, the field produced around 1,000 MMscfd gas. However, recently the production decline rose to around 7% annually, as the performance of multiple wells have gone down with declining reservoir pressure and water production. Therefore, to cut water production and arrest the annual field decline, various activities were carried out including cementing, tubing size optimizations, and chemical placements, but to no effect. Resultantly, a two-step workflow is developed that starts with selection of wells faced with rapidly declining production and high water-cut. These are then analyzed using production logging data for zonal contributions and contact movement. Next phase was to develop a comprehensive algorithm to analyze the re-processed seismic and geological parameters, integrated with reservoir simulation to identify the undrained area and quantify potential gain from the optimized sidetracks. Deploying the proposed approach yielded immediate returns in the form of initial gains of around 10 MMscfd gas production from the first two wells with addition of around 10-15 BCF reserves in the portfolio. Similarly, implementation of the strategy on another set of two wells resulted in production enhancement of 6 MMscfd gas and ~6BCF additional reserves from one of these wells. While the other well did not yield optimized results due to operational challenges which includes uncontrolled losses in complex and intricate fracture network. Consequently, this triggered the addition of fracture attribute study in the earlier developed workflow, further strengthening the sidetrack programs. While liquid loading and water breakthrough are common challenges pertaining mature assets, stereotyping one solution across the board may not result in optimum results. The proposed workflow delineates multiple factors for production gains including G&G analysis, well construction details, additional fracture-attribute study, and completion types, that can be adjusted to harvest the maximum rewards in such mature fields.

doi: 10.2118/214100-MS

Gas & Oil Technology Showcase and Conference

SPE-214100-MS

Country:

Asia (0.96)
North America > United States > Texas (0.47)

Genre: Overview > Innovation (0.40)

Geophysics: Geophysics > Seismic Surveying (0.68)

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

SPE Disciplines:

Well Completion > Hydraulic Fracturing (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
Reservoir Description and Dynamics > Reservoir Simulation (1.00)
(5 more...)

Technology: Information Technology (1.00)

Multi stage Frac & Testing of High Angle HPHT Ultra Sour Exploratory Well: Challenges Encountered & Mitigated

Abstract Reservoir production challenges are always escalated when the concentration of H2S and CO2 are extremely high. This paper highlights the challenges encountered, mitigation techniques used to overcome hurdles, and remaining tasks in testing the first deep high angle High Pressure High Temperature (HPHT) exploratory well completed with Multi-Stage Completion (MSC) in the presence of ultra-sour fluid (H2S-31% and CO2-38%) in Kuwait. The subject Jurassic well is drilled at a highly deviated angle up to 19,000 ft in measured depth (MD). The completion installed is composed of an open-hole MSC and three stages of frac ports tied back with a Liner Hanger to the upper 4.5 inch tubing. After setting the completion, the 15.8 ppg oil base mud (OBM) completion fluid was displaced with 11.6 ppg brine. DataFrac treatment and analyses were followed by acid fracturing treatment in all three stages. Post-fracturing well clean-up is achieved by continuously pumping Hydrogen Sulfide (H2S) scavenger to protect the entire surface test equipment set up. Employing self-containing breathing apparatus for personnel safety and having two flare pits permitted uninterrupted well testing for 13 days. During the well clean-up, the very high H2S and Carbon Dioxide (CO2)concentrations in knocked out fluid were 31% and 38%, respectively. However, due to the extremely high sour nature of reservoir fluid and limitation of separator metallurgy, the flow rate measurement is limited to only 2 hours. Various technical and operational safety challenges were safely handled during the well preparation, acid fracturing, testing, and flaring operation without any HSE incident. Moreover, continuous flow rate measurements are not achieved due to equipment limitations. Currently, a multi-phase flow meter (MPFM) which can handle high H2S and CO2 is under evaluation to conduct long term well testing to ascertain the production potential. The completion of three stage acid fracturing treatments and safely testing the high sour deviated well in HPHT conditions of an exploration well for the first time in the State of Kuwait is a remarkable success, paving the way for future field development in similar well conditions. However, production and processing of this highly sour fluid will be challenging for field development.

doi: 10.2118/214156-MS

Gas & Oil Technology Showcase and Conference

SPE-214156-MS

Country: Asia > Middle East > Kuwait (0.91)

Geologic Time: Phanerozoic > Mesozoic > Jurassic (0.67)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Government > Regional Government > Asia Government > Middle East Government > Kuwait Government (0.34)

Oilfield Places:

Asia > Middle East > UAE > Thamama Group > Shu'aiba Formation (0.99)
Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
(13 more...)

SPE Disciplines:

Well Completion > Hydraulic Fracturing (1.00)
Well Completion > Acidizing (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
(3 more...)

Deliberate Search for Stratigraphic Traps: A Success Story from Sabah Offshore

Das, Prabal S (Petronas Carigali Sdn. Bhd.) | Nayak, Satyabrata (Petronas) | Kurniawan, Trisakti (Petronas Carigali Sdn. Bhd.) | Huslan B Mohd, Azwari (Petronas Carigali Sdn. Bhd.)

Extended Abstract Abstract This article briefly discusses the workflow through which a gas discovery was made within the Late Miocene interval (Lower and Upper Stage IVD) from the structurally down-flank of a three-way fault closure, where previously an unsuccessful campaign was carried out in the structurally higher location. The causes for the failure were attributed to reservoir absence and trap incompetency. An attempt was made to understand the causes of facies variations and their limits through an integrated sequence stratigraphic approach. This model was further concretized through post-stack attributes where the limits of the seismic facies were prominent. A quantitative interpretation (QI) study coupled with forward modelling helped de-risk the reservoir presence and fluid types. Rock physics modelling work, including shear log prediction, rock property modelling, depth -trend analysis, followed by simultaneous inversion and sand probability volume generation, reveals that the deeper part of Upper Stage IVD and Lower Stage IVD intervals were shale-out and pinch-out, respectively, for the earlier campaign. Likewise, sand-dominated facies are likely at the down-dip for both intervals with an effective lateral seal up-dip (due to facies change and pinch out). Finally, this integration led to a hydrocarbon discovery in a previously written-off fault block and proved a potential stratigraphic trap presence in this area. The well encountered 50 m of net gas-bearing sand within both intervals. This approach could further facilitate exploring stratigraphic play (s) in a similar geological setup.

International Petroleum Technology Conference

doi: 10.2523/IPTC-22846-EA

IPTC

IPTC-22846-EA

Country: Asia > Malaysia (0.30)

Geologic Time: Phanerozoic > Cenozoic > Neogene > Miocene (0.78)

Geophysics:

Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Offset (AVO) (0.71)
Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.68)

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

Oilfield Places: Asia > Malaysia > Sabah > South China Sea > Sabah Basin (0.99)

SPE Disciplines:

Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)

Technology: Information Technology (0.49)

Abstract The Greater Burgan field in South-East Kuwait is the world's largest sandstone oilfield and the second-largest conventional oilfield. The Wara reservoir, in the Greater Burgan field, is a prolific sandstone oil-producing formation. Peripheral water injection into the Wara reservoir is in progress for pressure maintenance and to improve oil recovery from the flank areas. Polymer injection has also been identified as a practical EOR method that can potentially increase oil production and recovery from the Wara reservoir. In view of that and, as a follow-up to a previous Long-Term Polymer Injectivity Test (LTPIT) (Murayri et al. 2022), a second LTPIT was carried out targeting a different area within the Wara reservoir. This paper describes elements of the polymer injection predictions approach, results obtained from a dynamic simulation sector model, before and after polymer injection, in pursuit of phased commercial polymer-flooding development using fit-for-purpose modularized water treatment and polymer mixing/injection facilities. Prior to the commencement of polymer injection, a representative 3x3 km sector was extracted from the full-field dynamic model. A fine grid numerical simulation model was then history matched and calibrated using production/injection history and Step Rate Test (SRT), Pressure Fall-Off (PFO), and Injection Logging Tool (ILT) and High Precision Temperature-Spectral Noise Logging (HPT-SNL) surveillance data. This model was set for predicting polymer injection rates to ensure injection under matrix conditions, at different polymer concentrations, to guide field implementation over a period of 3 months. Pre-LTPIT modeling results demonstrated that injection at commercial rates of >2,000 bpd is possible with polymer concentrations ranging from 1,500 to 1,800 ppm in accordance with the targeted in-situ polymer solution viscosity. During LTPIT field implementation, downhole pressure and temperature were monitored real-time in addition to wellhead pressure, injected polymer solution viscosity and injection rates to evaluate performance and update the sector model. Thereafter, reservoir simulation sensitivity runs were extensively investigated to design an optimal phased commercial development plan. This plan was developed by optimizing well requirements, injected polymer Pore Volume (PV) and concentration. A polymer PV of 0.8 and a concentration of 1,800 ppm were recommended accordingly in conjunction with 40 acre inverted 5-spot patterns. Economic evaluation was performed while considering water-flooding performance as a baseline. The incremental benefits associated with oil production gains and reduced water handling requirements were evaluated against the envisioned investment in additional wells and polymer injection. The optimal case showed an incremental oil recovery factor of 7% over a period of 10 years. This paper presents a case study wherein fit-for-purpose reservoir modelling is integrated with LTPIT surveillance/monitoring data to maximize the techno-economic benefits of phased commercial polymer-flooding in the Wara reservoir of the Greater Burgan field.

doi: 10.2118/213455-MS

Middle East Oil, Gas and Geosciences Show

SPE-213455-MS

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

Industry:

Energy > Oil & Gas > Upstream (1.00)
Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.36)

Oilfield Places:

Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Wara Formation (0.99)
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)
(4 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)

Technology: Information Technology > Modeling & Simulation (0.54)

Comprehensive Design and Diagnostic Approach for Horizontal Completions in Carbonate Environment

Alobaid, Hashem (Saudi Aramco) | Khan, Abdul Muqtadir (Schlumberger) | Almulhim, Abdulrahman (Saudi Aramco) | Hansen, Jon (Saudi Aramco) | Kabannik, Artem (Schlumberger)

OnePetroOctober, 2022

Abstract The development of tight carbonate reservoirs is moving towards drilling and completing wells with longer laterals. This leads to challenges of longer completion time, high number of fracturing stages, longer interventions, and eventually higher costs. Design cycle implementation is required to devise an engineered strategy to mitigate these challenges. Lateral landing was conducted based on the cross-section grid consisting of two offset horizontal wells completed with up to 13 fracturing stages. A longer lateral greater than 6,000 ft was drilled compared to 4,000 ft in offset wells to get the production potential. With a strategic design involving engineered chemistry and numerical simulation models, a cluster design was devised to reduce to stages. A mathematical algorithm employing tube wave velocity calculations was used as a diagnostic to ensure diversion success after each stage. The horizontal lateral was landed traversing the prolific layer. Stage reduction sensitivity simulations were conducted using multiphysics numerical models and novel beta factor workflows to evaluate the extent of stage reduction. The design was extended to plan for five stages only, with increased number of perforation clusters per stage. The reliable diversion chemistry utilized was accompanied by a revised perforation length as dictated by the beta factor workflow. A total of 39 clusters, 2-ft each, were distributed across 6,000 ft with four mechanical isolation plugs. A novel nonintrusive diagnostic model built on mathematical fundamentals of wave travel time was used with a Bayesian statistical approach after each diversion pill placement to ensure fracture fluid entry points and enough coverage in each stage. The high fluid viscosity and operating pumps during the water hammer events resulted in low signal-to-noise ratio in the input data. To overcome these limitations, the water hammer events were processed with a combination of two newly developed algorithms: predictive deconvolution and comb filter, which produced more robust results than the traditional approach. Consequently, the well production was analyzed to show equivalent or higher productivity index compared to the offset laterals with up to two times higher stage count. The paper presents a unique example in which an experiment was fully engineered from design to evaluation and monitored with reliable diagnostics. This example gives a blueprint for future completion designs.

doi: 10.2118/210977-MS

SPE-210977-MS

ADIPEC

Country:

Asia > Middle East > Saudi Arabia (0.47)
North America > United States > Texas (0.29)
Asia > Middle East > UAE > Abu Dhabi > Abu Dhabi (0.16)

Geophysics: Geophysics > Seismic Surveying (0.93)

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

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
Well Completion > Completion Installation and Operations > Perforating (1.00)
(2 more...)

Technology:

Information Technology > Artificial Intelligence > Machine Learning (1.00)
Information Technology > Modeling & Simulation (0.66)

Application of Logging While Drilling - Nuclear Magnetic Resonance in Reservoir Evaluation and Geosteering: A Case Study in Marrat Reservoir, Umm Roos Field, West Kuwait

OnePetroOctober, 2022

Abstract The Jurassic Marrat reservoir in Umm Roos field of West Kuwait (WK) is a low-permeability carbonate reservoir with heterogeneous petrophysical character that limited the predictability of reservoir properties and highly deviated development wells are preferred to maximize the exposure of the reservoir. However, there is an environmental risk and high operational cost when running radioactive-based porosity logging tools in such complex well profiles. To avoid that risk, Nuclear Magnetic Resonance (NMR) with conventional resistivity and gamma ray in a logging while drilling (LWD) program is proposed to achieve real-time formation evaluation and efficiently support well placement to maximize the reservoir contact. This paper presents the application of LWD-NMR as an alternative solution to evaluate reservoir properties as well as to land the highly deviated well successfully in the best reservoir sweet spots to achieve the maximum outcome for production.

doi: 10.2118/211699-MS

SPE-211699-MS

ADIPEC

Country:

Asia > Middle East (1.00)
North America > United States > Texas > McMullen County (0.61)
North America > United States > Virginia > Virginia County (0.40)
(2 more...)

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

Oilfield Places: North America > United States > Texas > West Gulf Coast Tertiary Basin > Roos Field (0.99)

SPE Disciplines:

Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

Technology:

Information Technology > Sensing and Signal Processing (1.00)
Information Technology > Architecture > Real Time Systems (0.91)