The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Ekpe, J. (KOC Kuwait Oil Company) | Al-Shehab, A. Y. (KOC Kuwait Oil Company) | Al-Othman, A. (KOC Kuwait Oil Company) | Baijal, S. (KOC Kuwait Oil Company) | Nguyen, K. L. (KOC Kuwait Oil Company) | Al-Morakhi, R. (KOC Kuwait Oil Company) | Dasma, M. (KOC Kuwait Oil Company) | Al-Mutairi, N. (KOC Kuwait Oil Company) | Verma, N. (KOC Kuwait Oil Company) | Quttainah, R. B. (KOC Kuwait Oil Company) | Janem, M. (Reservoir Group/Corpro) | Deutrich, T. (CORSYDE International) | Wunsch, D. (CORSYDE International) | Rothenwänder, T. (CORSYDE International) | Anders, E. (CORSYDE International) | Mukherjee, P. (MEOFS Middle East Oilfield Services)
Abstract The successful recovery of pressurized core samples from an unconventional HPHT reservoir is presented. Optimized methods and technologies such as implementation of Managed Pressure Drilling (MPD) technique as well as coring technology customization and adaptation are discussed. Results from offset wells are compared and a best practice method is described how to recover pressurized cores from the organic rich Najmah Kerogen in West Kuwait. A coring BHA was configured using a modified version of the LPC Core Barrel hence allowing for the first time to consider recovering pressurized core samples from a well with a very challenging operating envelope. Furthermore, the provided methodology ensures that well conditions are maintained to allow for a pressurized core recovery in most stable wellbore environment avoiding any unwanted subsurface problems. With three consecutive runs planned on for the pressurized coring using MPD each 10 ft., the results obtained showed a successful coring operation of which typical wellbore downhole issues were avoided with no loss time due to well ballooning, mud losses and well kicks. The successful coring operations as well as all subsequent on-site analysis procedures showed possibility to recover pressurized core samples from unconventional formations with high formation pressure in a safe and effective manner. Avoiding core damage due to petal-centerline fractures and disking is fundamental in quantifying natural fractures in this unconventional reservoir. This novelty approach of core barrel system modification and using MPD technique in acquiring the pressurized cores has made it possible to obtain representative near in-situ data to better reservoir interpretation and quantification of natural fractures. The method has a great potential to ensure high core recovery in high angle wells while delivering superior reservoir fluid and rock information which is not obtainable by other means.
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)
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.
Tellez Arellano, Aaron G. (Department of Petroleum Engineering, Khalifa University of Science and Technology, UAE) | Hassan, Anas Mohammed (Department of Petroleum Engineering, Khalifa University of Science and Technology, UAE) | Al-Shalabi, Emad W. (Department of Petroleum Engineering, Khalifa University of Science and Technology, UAE) | AlAmeri, Waleed (Department of Petroleum Engineering, Khalifa University of Science and Technology, UAE) | Kamal, Muhammad S. (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals) | Patil, Shirish (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals)
Abstract The global interest in enhanced oil recovery (EOR) methods has been increasing recently as a source of satisfying the ever increasing energy demand. This is due to maturing of most of the existing and significant hydrocarbon reservoirs as well as the very limited number of new oil major reservoir discoveries. This is added to the challenging existing reservoirs conditions such as viscous oil, mixed-to-oil wettability, heterogeneity, and high temperature high salinity (HTHS). Polymer flooding is one of the robust and inexpensive EOR processes that improves sweep as well as displacement efficiencies. However, modeling of polymer flooding is a challenging task due to the difficulty in portraying all of the key physico-chemical aspects such as polymer rheology, adsorption equilibrium, inaccessible pore volume, and behavior against high salinity and hardness. This challenge has shifted the attention and efforts towards developing reliable reservoir simulators as tools for predicting and mitigating the risks-involved with polymer flooding projects. In this study, we present a critical review of recent modules from different numerical simulators with chemical EOR (cEOR) competences such as CMG-STARS, ECLIPSE-100, and UTCHEM to model polymer properties. The review starts with description of numerical formulation and applications for different simulators. This is followed by descriptions of polymer models including viscosity, salinity effect, rheology, adsorption, and permeability reduction. Afterwards, the assessment of different simulators is presented through polymer flooding simulation cases as reported in the literature. It is to be noted that the overall results did not provide an insight into algorithm efficiency or computational cost of different numerical simulators, but instead mainly focused on the mechanistic modeling of the process with different parameters. The results suggest that with an appropriate mechanistic modeling of polymer flooding, there is potential for accurate prediction and optimization of various polymer flooding projects under diverse conditions, which is expected to positively impact the oil recovery efficiency and related economics. This study provides insights about the application scopes of different numerical simulators and their competences under diverse reservoir scenarios in order to obtain optimized performance of a polymer flooding field project.
Hamadah, Omar Abdulrazzaq (Kuwait Oil Company) | Al-Ibrahim, Abdullah Ali (Kuwait Oil Company) | Najaf, Abdulaziz (Kuwait Oil Company) | Slama, Mohamed Hedi (SLB) | Badrawy, Kareem (SLB) | Molero, Nestor (SLB) | Pochetnyy, Valentin (SLB) | Sebaih, Mohannad Adel (SLB)
Abstract Even though technology development has leveraged a consistent grow in the number of rigless interventions, many remedial programs still require the support of workover rigs. In South-East Kuwait, mechanical constraints at the production tree tubing hanger prevented the operator to install the blowout preventer (BOP) of the workover rig following the conventional practices and called for a custom-fit approach to enable the required number of pressure barriers to intervene this well. The intervention approach relied on instrumented CT for well killing and temporary well suspension. CT real-time downhole telemetry enabled accurate placement and setting of a through-tubing inflatable and retrievable packer (TTIRP) inside the production tubing. Once the packer integrity is pressure tested in both directions, CT is disconnected, and then a sand plug followed by an acid soluble cement plug are spot on top of the TTIRP. Upon confirmation of cement plug integrity, the workover rigs come into play, nipples down the production tree and installs the BOP. Instrumented CT is then rigged up and run back-in-hole to dissolve the cement plug, circulate the sand out and recover the TTIRP to surface. The candidate well where this innovative intervention workflow was implemented had a maximum potential wellhead pressure in the order of 1,100 psi and a plug-back true depth (PBTD) near 10,100 ft. The well was completed with 3 1/2-in. production tubing set close to 3,500 ft MD and 8 5/8-in. casing until PBTD. An e-line through-tubing puncher was carried out in the production tubing before the first CT run to enable circulation of killing fluid. TTIRP setting depth was conditioned via instrumented CT and high-pressure rotary jetting tool, and displacing the wellbore to brine, resulting in a shut-in wellhead pressure near zero psi. In the next CT run, TTIRP was positioned around 620 ft, and important steps like depth correlation, packer inflation, and packer anchoring tests were actively monitored using real-time downhole measurements. Both positive and extended inflow tests using live downhole pressure monitoring were carried out to confirm the effectiveness of the TTIRP sealing before the CT was disconnected from the packer assembly. Once the TTIRP was released, the temporary suspension was completed following the methodology described above. Finally, the well was closely observed at surface with zero pressure for more than 24 hours, receiving acceptance from the operator to service the well. Upon completion of the workover program, the estimated saving by eliminating deferred production was estimated to be around 200,000 bbls. This case study from South-East Kuwait discusses a custom-fit approach via instrumented CT and TTIRP for restoring well integrity in wells planned for workover rig intervention where mechanical constraints at production tree prevented installing the workover rig BOP, and the lessons learned are now reference for operators in the Middle East with wells with similar challenges.
Abstract Asphaltene deposition has been observed in some wells within low-pressure areas in B oilfield during depletion. It is therefore concerns about asphaltene precipitation in the reservoir casued by decreasing pressure are raised. In this study, the impact of asphaltene deposition on water flooding in B oilfield was assessed by reservoir simulation. This work built a new simulation model and investigated five kinds of formation damage due to asphaltene precipitation, which are porosity loss, permeability impairment, wettability alteration, relative permeability and capillary pressure changes, and oil viscosity variation. The instantaneous porosity loss equals to the volume of compressed pore and deposited asphaltene per grid block volume. The permeability impairment is calculated considering rock compressibility, asphaltene deposition on rock surface and throat plugging by asphaltene. The wettability alteration, oil-water relative permeability and capillary pressure changes were investigated according to published laboratory experiments, Gibbs adsorption theory and the modified Corey type model. Moreover, the oil viscosity variation was calculated by using a linear function model. The simulation results show that asphaltene deposition in the reservoir would easily cause well skin and reduce the productivity index. As a result of wettability alteration caused by asphaltene surface deposition, the predicted oilfield water cut increases more quickly than that of the model without considering asphaltene deposition. Besides, the oil recovery factor reduces significantly when the reservoir pressure maintenance level is far lower than the upper onset pressure. The preferred reservoir pressure in a specific oilfield should be optimized based on sensitivity simulation cases to obtain a high oil recovery factor and slow water cut increase. B oilfield is recommended to maintain reservoir pressure around 5000 psi.
Muqeem, Saleh (Kuwait Oil Company) | Al-Mulaifi, Mohammed (Kuwait Oil Company) | Al-Assil, Yasser (Kuwait Oil Company) | Sekhri, Anish (Kuwait Oil Company) | Sulaiman, Mai Yacoub (Kuwait Oil Company) | Shekhar, Chandra (Kuwait Oil Company) | Abdelrahman, Ibrahim (Kuwait Oil Company) | Abdulkareem, Talal (Kuwait Oil Company) | Homi Jokhi, Ayomarz (Schlumberger) | El Kady, Mahmoud (Schlumberger) | Al Saad, Naser (Schlumberger) | Al Muzaini, Shahad (Schlumberger) | Mataqi, Fatemah (Schlumberger) | Al Harbi, Saad (Schlumberger) | Al Kanderi, Naser (Schlumberger) | Herrera, Delimar (Schlumberger) | Halma, Jeremy (Schlumberger) | Ibrahim, Sameh (Schlumberger) | James, Biju (Schlumberger)
Abstract Drilling the 16-in. section in Minagish field wells in western Kuwait is among the most challenging well sections. Challenges include drilling through severe loss conditions, destabilized shale, and deteriorating hole conditions. These conditions can result in hole collapse or lost in hole of the drill string that requires sidetracking. The objective of project presented in this paper was to develop an engineered solution to drill through the difficult zones, lessen nonproductive time, and reduce the total well cost. The solution proposed was to use casing-while-drilling technology with a drillable bit and drill through the fractured dolomitic limestone and sandstone formation while simultaneously setting casing. The drillable casing-while-drilling bit was specifically designed and engineered to conform to the formations in the field. The drillable casing-while-drilling bit is manufactured with a material that can be drilled out with either conventional roller cone or fixed cutter bits. A plastering process was used, which smears the cuttings generated by drilling against the borehole wall, seals the pores or fractures in the formation, and helps reduce fluid losses while maintaining well integrity. The first successful 16 × 13.375-in. casing-while-drilling job in Minagish field reduced well delivery time for the operator and saved 27 rig days with substantial savings in the total well cost. The section was drilled successfully while encountering total mud losses through fractured dolomitic limestone and sandstone formations. Continued drilling managed to reduce losses with 30 to 50% returns and reached the target depth. Preventing the risk of losing the bottomhole assembly in the hole and alleviating the use of multiple cement plugs saved additional cost for loss-cure plugs to heal the loss-prone formations. After reaching the target depth, cementing, pressure testing of the casing, and drillout of the drillable casing-while-drilling bit using a rerun fixed cutter bit were performed successfully. On an average, eight wells are drilled per year in this field. With the successful implementation and the savings obtained by using this casing-while-drilling technology in the first test well, there is the potential for substantial annual cost savings, help the operator deliver wells in less time, and eventually increase production by increasing the number of wells drilled per year.
Al-Hamad, Hamad (Kuwait Oil Company) | Sarah, AlSamhan (Kuwait Oil Company) | Al-Naqi, Meqdad (Kuwait Oil Company) | Sajer, Abdulaziz (Kuwait Oil Company) | Hussein, Assef (Schlumberger) | Ni, Qinglai (Schlumberger) | Kumar, Surej (Schlumberger)
Abstract As a field development strategy, KOC is developing highly depleted reservoir. The field has been experiencing wellbore instability issues. Some recent wells have encountered stuck pipe and mud losses in clastic and carbonate sections. To reduce geomechanical related Non-Productive Time and rig days, it is important that combined effect of in-situ stress state and well trajectory on wellbore stability should be thoroughly investigated. Rock mechanical behaviours also need to be evaluated to optimize drilling practice. The growing appreciation of the effects of regional tectonics is making it crucial to move away from simplified characterisation of rock behaviour and to turn into advanced geomechanical modelling techniques to engineer better wells and fields. The advanced 3D coupled Geomechanical-Fluid-Flow modelling method combines input data of different origin, such as seismic data, petrophysical data, fluid-flow data and well logs. With such an integrated model, spatial variations of the in-situ stresses in the field are obtained due to reservoir structure, presence of discontinuities as we as because of reservoir depletion. The whole production history spanning seventy years was simulated. The 3D coupled geomechanical model was able to reproduce the observed wellbore instability events for fifteen wells drilled at different times and various reservoir depletion stages. Drilling instability events included tight spots, cavings and stuck pipe in major clastic sections; and mud losses in carbonate sections. Two blind tests for wells not used for model calibration were carried out to examine the mechanical properties, stress profiles and caliper logs within various formations. The match between the model prediction and the data was in good agreement. In addition, a 3D description of the mud weight was computed, which allowed to obtain drilling maps across the field highlighting zones of high, medium and low drilling risks. Such drilling maps enabled optimizing placement of future planned wells and provide guidance in mud weight design. Nevertheless, drilling through faults requires careful attention due to the localized stresses concentration developing along their geometries. High resolution near wellbore stability analysis helped to optimize the drilling mud weight for wells crossing faults. The powerful combination of multidisciplinary domains into one integrated 3D geomechanical model improved the understanding of subsurface behaviour. With such an integrated model, complex technical challenges as drilling complexities in the study field can be achieved and hence decreases the Non-Production Time by avoiding problems prior to their occurrence. The calibrated model showed satisfactory predictability for the whole production period and thus is used as a mitigate problem measure to placement of new planned wells.
Evro, Solomon (Kuwait Oil Company) | Alshamali, Adnan (Kuwait Oil Company) | AL-Faresi, Fahad (Kuwait Oil Company) | Mishari, Al-Qattan (Kuwait Oil Company) | Al-Ostad, Nejoud (Kuwait Oil Company) | Krasnova, Galina (Kuwait Oil Company) | Hayat, Laila (Kuwait Oil Company) | Suresh, andana (Kuwait Oil Company) | Mandani, Hasan (Kuwait Oil Company) | Jimenez, Carlos (Kuwait Oil Company) | Ali, Sher (Kuwait Oil Company)
Abstract The Tayarat formation extends over a large area; this formation has a diverse and complex geology and has heavy oil fluid system. A previous review of the analogous technologies that apply to the Tayarat heavy oil formation shows that it would be economically impossible to deploy a single reservoir development technology in all the areas of the field. In this project, we evaluated cyclic steam stimulation strategies focusing on applying different well completions. We have applied a compositional numerical simulation model using CMG Stars to investigate the application of different cyclic steam stimulation strategies. This includes using a traditional vertical well with a single steam injection point in the entire zone of the reservoir. We also investigated the use of vertical wells with dual string completion, where the short string injected into the upper parts of the formation while the long string injected into the lower part of the reservoir. With the horizontal well injection, we investigated open-hole completion and the case of using a horizontal well with multi-stage hydraulic fracturing. The potential of injecting steam at a higher rate with horizontal wells is attractive and requires more investigation. Apart from reducing the well count, we could overcome the surface constraints challenge in the field by stepping out of the congested areas and placing the horizontal section in the targeted part of the formation. With the advances in horizontal wells with multi-stage hydraulic fracturing in the industry, carbonate reservoirs such as Tayarat with low permeability could benefit from more reservoirs contact and possibly better steam distribution if we introduce adequate hydraulic fracture stimulation in the formation. The results of this study show that we could reduce our drilling footprint substantially by implementing a horizontal well with multi-stage hydraulic fracture stimulation in developing parts of the Tayarat carbonate heavy oil reservoir. Cyclic steam injection with vertical wells completed with dual strings shows a production advantage over a similar vertical well completed with a single string in similar zones. At the same time, horizontal wells with multi-stage hydraulic fracturing stimulation offer marginal benefits. The risk of increased hydraulic stimulation costs could undermine the value created by horizontal drilling and completion.
Sebea, Salem Hamad Al (Kuwait Oil Company) | Abu-Eidah, Abdullah Ibrahim (Kuwait Oil Company) | Patra, Milan (Kuwait Oil Company) | ALKhayouti, Malak Yousef (Kuwait Oil Company) | Bumijdad, Mohammed Mousa (Kuwait Oil Company) | Al-Hamdan, Abdulaziz (Kuwait Oil Company) | Khandelwal, Nakul (Halliburton) | Chawla, Sapna (Halliburton) | AlWazzan, Abdulatif (Halliburton) | Alkreebani, Mohammad (Halliburton) | Travesso, Joshua (Halliburton)
Abstract Multilateral wells offer multiple benefits to oil and gas operators, including lowering the field development cost by minimizing wellsite construction work and increasing reservoir contact leading to enhanced reservoir production. They also present challenges, with each leg requiring separate intervention and uniform stimulation to gain full advantage of these complex wells. An operator in Kuwait drilled a 2-leg level 1 multilateral well to enhance production from the Mishref formation. Mishref is a fast-depleting reservoir requiring an extended contact area to drain the reservoir uniformly and efficiently. The main challenges with multilateral intervention include identifying the junction depths, gaining lateral entry, and confirming the correct lateral entry. To overcome these challenges, the operator identified the unique technology of utilizing Real-Time Hybrid Coiled Tubing (RTHCT) with an Electric Multilateral Tool (EMLT). Diagnostics using Distributed Temperature Sensing (DTS) were also used to compare pre and post-stimulation effectiveness. Intervention into a level 1 multilateral well presented several challenges, and RTHCT with the EMLT were successfully used to overcome these. The solution includes a hybrid fiber optic and electrical cable installed in the CT string and a Modular Bottom Hole Assembly (MBHA) equipped with various sensors. An electrically controlled indexing tool, inclination sensor, tool-face sensor, downhole camera, hydraulic knuckle joint, and pulsating stimulation tool were used as part of the BHA to enable real-time diagnostics and dynamic controls from the surface to successfully enter and stimulate both the lateral legs. This customized solution helped identify each different lateral without the need to tag the bottom of each lateral. This paper focuses on applications, strategies, and benefits of specific tool configurations developed for multilateral well intervention, which enabled the stimulation of both the Mishref laterals. Also discussed are the DTS diagnostics used to identify any thief and impermeable zones. Pre and post-stimulation diagnostics were performed to identify the effectiveness of the stimulation treatment. This paper includes strategies that address proper tool selection, confirmation of lateral entry, hydrostatic pressure balance, borehole stability, and acid design. It also explores the potential of new, synergistic strategies and work processes planned for stimulation of the Mishref reservoir.
Alkandari, Shaikha (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Alsaleh, Zainab (Kuwait Oil Company) | Jaafar, Dunya (Kuwait Oil Company) | Jasem, Mariam (Kuwait Oil Company) | Mudvakkat, Anandan (Kuwait Oil Company) | Khan, Junaid (Kuwait Oil Company) | Alaassar, Ahmad (Kuwait Oil Company) | Perez, Godo (British Petroleum Company) | Rjabli, Nuran (British Petroleum Company)
Abstract As oil fields mature, producing more oil out of maturing reservoirs entails more water production. It is essential to have a successful water management process to be introduce, one that can handle substantial volumes of water produced in order to sustain crude oil production. At the early stage of the Greater Burgan Field water management was not a major concern. Most of its crude oil was dry and easy production with little water from Burgan & Wara reservoirs in Greater Burgan Field. With maturing of the field, South & East Kuwait Asset has started experiencing an increase in water production from its maturing reservoirs. Also starting water flooding in Wara reservoir to increase oil recovery increased water cut with oil production as expected. These changes made the production facilities to become constrained that cannot fully handle produced water volume and result in production deferral. To mitigate the high water cut challenges, South East Kuwait set up a multidisciplinary team to review and come up with actions to tackle the produced water handling challenge. The team looked at an operational initiative to maintain the long-term disposal option of disposing produced water into Shuaiba formation. Shuaiba formation is below Burgan reservoir. During drilling the drilling team encountered heavy fluid losses in Shuaiba. This experience led the study team to support the option of disposing effluent water into fractured Shuaiba carbonate. Shuaiba formation is classify as carbonate formation, full of vugs and fractures resulted from dissolution due to ancient underground water movement, the dissolution led to collapse And creation of large vugs and fractures around the collapsed area. The collapsed area and fractures are the main mechanism for storage of effluent water and increasing disposal capacity for the production facility. The plan is to drill Horizontal disposal wells targeting the Karst to intercept those vugs and fractures. The team saw a promising option to drill in Shuaiba, to increase the chance of loss fluid circulation and enhance facility capacity. After drilling few wells and encountering total loss in the horizontal fractured section, along the edge of the karst, and performing injectivity disposing test, the wells showed ability to take up high water rates more than (50,000 BWPD). Based on the success of these disposal wells, Production operations bottlenecks are resolved in disposal well capacity and increasing it to more than (500,000 BWPD). Disposing in Shuaiba, formation will not require any treatment facilities and is an environmentally friendly long-term option