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:
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Fukuda, K. (ADNOC Offshore) | Biyanni, H. (ADNOC Offshore) | Toma, M. (ADNOC Offshore) | Moslim, S. (ADNOC Offshore) | Toki, T. (ADNOC Offshore) | Zaabi, A. Al (ADNOC Offshore)
Abstract Hollow bit method was introduced and implemented in Offshore Abu Dhabi Field to eliminate the cement quality uncertainty and improve the slot recovery performance. Hollow bit method improved the overall slot recovery performance by 40% compared to other slot recovery methods, reducing operation duration from 20.8 days to 12.5 days. In this paper, hollow bit technical overview and best practices which can be implemented to similar application are presented
Sulaiman, A. Y. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | AlHammadi, I. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Al Ali, S. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | El-Sheikh, H. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Al Ghafeli, S. K. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Shokry, A. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Abdi, R. M. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Abdulla, M. F. (Adnoc Offshore, Abu Dhabi, United Arab Emirates) | Yakovlev, T. (Interwell Middle East, Abu Dhabi, United Arab Emirates) | Ross, S. (Interwell Middle East, Abu Dhabi, United Arab Emirates)
Abstract As wells completed with wireline retrievable downhole safety valves are becoming mature, issues related to seal bore and nipple profile tend to develop, causing the safety valve to be non-integral. Without a fully functioning downhole safety valve, these wells cannot produce and must be shut in. One option to overcome this issue is to utilize an Insert Valve Carrier (IVC) connected to the existing downhole safety valve (DHSV). The IVC has an anchoring mechanism to hang the system on depth, replacing the function of the damaged nipple. Also, it is equipped with upper and lower sealing elements to seal across the existing control line outlet in the tubing providing hydraulic fluid to operate the safety valve. An electronic setting tool sets the anchors at the pup joint slightly above the safety valve nipple while positioning the sealing elements across the control line outlet. The system is simple to use and can easily be set with Slickline, Electric Line, or Coiled Tubing with CCL capability for correlation or a No-go assembly. Several successful jobs were conducted between 2021-2022 in 4-1/2″ and 7″ completions in the Offshore Abu Dhabi field. Before mobilization, System Integrity Test is performed to ensure the system passes the pressure test and the safety valve functions properly. In this operation, the IVC and the safety valve were set using an Electric Line, taking advantage of real-time reading from the CCL for correlation. Once on depth, a signal was sent from the surface, setting the anchors and sealing elements. A normal procedure to apply pressure in the control line was performed. When the pressure holds, it provides a positive indication that the packing elements seal properly. An inflow test on the flapper was performed to confirm its integrity. Following the installation, flow tests were performed at different rates to ensure the system worked fine and evaluate the potential. This system has successfully restored the downhole safety valve functionality, which permits the wells to produce again after being inactive for a long time. In addition, the success of this system eliminates the need for expensive workovers.
Kim, Yonghwee (Baker Hughes) | Al-Quoud, Khaled Jamal Ibrahim (Kuwait Oil Company) | Sahib, Mohammad Raffi Madar (Kuwait Oil Company) | Sergeev, Evgeny (Kuwait Oil Company)
Abstract Operators commonly adopt waterflooding as a secondary recovery method to maintain reservoir pressure and displace remaining oil for production enhancement. Effluent and seawater have been injected into the Upper Burgan formation, which contains multiple layers of sand reservoirs, in the North Kuwait Raudhatain field. Well-based surveillance to understand post-waterflooding hydrocarbon distribution is essential for new perforation additions. Formation saturation monitoring for cased wells is widely performed with pulsed neutron well logging techniques. Pulsed neutron well logging provides time-based thermal neutron capture cross-section (i.e., sigma log) and energy-based element-specific ratios (i.e., carbon/oxygen (C/O) logs). Formation water salinity must be known and high to use sigma data to quantify formation fluids. When formation water salinity becomes a variable due to effluent and seawater injection, sigma log-based saturation analysis is not applicable. A salinity-independent measurement that distinguishes between oil and water is required; consequently, a C/O log must be used to obtain saturation profiles in mixed-water salinity reservoirs. The Upper Burgan formation’s initial water salinity in the Raudhatain field is high (i.e., approximately 220-240 kppm NaCl equivalent); thus, water saturation computation was performed with a sigma log. After the injection of effluent and seawater (mixed-water salinity ranges from 50 kppm to 170 kppm) was started, formation oil volumes must be evaluated using C/O logging. A well-specific Monte Carlo Neutron Particle (MCNP) model and two-detector-balanced C/O data sets were combined to compute oil saturation. We demonstrate multi-well case examples delineating well-based formation saturation profiles in post-injection reservoir conditions. A comparison of sigma- and C/O-based saturation analyses revealed water-flooded zones. Time-lapse sigma data sets highlighted how the water injection impacted thermal neutron capture cross-section measurements. Additionally, multi-detector, time-based nuclear attributes were used to evaluate formation properties and the presence of hydrocarbon-bearing sands. Following pulsed neutron log interpretation, subsequent add-perforation activities were performed; consequently, by-passed or remaining hydrocarbon was successfully produced. Evaluation of current formation fluid distribution in areas of the field where mixed-water salinity exists is challenging. Integrating sigma, C/O, and auxiliary pulsed neutron logs determined the remaining formation oil distribution and volume. The optimized perforation strategy to maximize oil production from existing wellbores was executed.
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.
Abstract The first microseismic monitoring operations of hydraulically stimulated wells were run in Bahrah and Sabriyah oilfields, Northeastern Kuwait. The main objective was to evaluate the capacity of the microseismic in optimising the fracturing process and consequently improving the production of these reservoirs. The major phases of such monitoring projects are sensors network design, deployment, acquisition, data processing, results delivery, and interpretation. Fit-for-purpose monitoring networks were designed by modelling the expected sensitivity and location accuracy of various sensors geometry scenarios, considering local reservoir properties. Geophones were deployed in observation wells nearby treatment wells to record the seismic waves emitted by the microearthquakes induced by the rock fracturing process. This seismicity was located and characterised to image the fracture networks growth under the effect of pumping. From this, fracture geometry parameters were assessed, stress and hazard characterised, unexpected behaviours were monitored and analysed. By providing information in real-time during rock stimulation operations, microseismic monitoring successfully helped improving production while maintaining a focus on the risk assessment indicators. In Bahrah, seismic response to the treatment was assessed for the target carbonate formation Mauddud, evaluating stimulation effectiveness while characterising unexpected and unwanted behaviours. In Sabriyah, fracture geometry estimates helped calibrating injection models and fine-tuning stimulation plans. Furthermore, a strong focus was also placed on monitoring hazard and anomalies in the Tuba carbonate formation being stimulated near a natural fault. Monitoring procedure, results and lessons learned from these projects can be transferred to other existing or upcoming wells to be drilled in the same formations, adding value to these reservoirs by optimising the fracture design, and making hydrocarbon recovery safer and more efficient. This paper reports on the first usage of microseismic monitoring in Bahrah and Sabriyah oilfields in Kuwait. Monitoring met the initial objectives and both the approach as well as results are now a baseline for the effective development of hydraulic stimulation in these reservoirs and others with similar characteristics.
Al-Sabea, Salem (Kuwait Oil Company) | Patra, Milan (Kuwait Oil Company) | AbuEida, Abdullah (Kuwait Oil Company) | Ali, Sulaiman Mohammad (Kuwait Oil Company) | Asthana, Saurabh (Packers Plus Energy Services) | Hadi, Ahmed (Packers Plus Energy Services) | Gholoum, Saleh Mahdi (Kuwait Oil Company) | Singh, Abhishek (Kuwait Oil Company)
Abstract Horizontal wells drilled in Kuwait Oil Company (KOC) targeting tight carbonate Mishref reservoir in West Kuwait Minagish development fields provided increased reservoir contact area leading to higher production rate and wider access to available hydrocarbon reserves. Large wellbore radius in these open hole horizontal laterals have resulted in increased friction losses during production phase. Later, with flow equalizing completion techniques, ultimate recovery from the reservoir increased and stable production was achieved during the early phase of the reservoir. However, accessing these long horizontal laterals was a challenge and coiled tubing acidizing treatments helped achieve permeability improvements only upto a certain extent. Majority of the reservoir sections with lower permeability were unaccessed and left untreated. Limited pumping rates through coil tubing could achieve few inches of radial penetration into the formation due to limited amount of acid dosage in the stimulation design. It has also been observed that bullheading treated only the heel section of the horizontal well, especially in the case of carbonate formation where acid stimulation is considered for productivity improvement. Studies carried out via Production and Temperature logging concluded that large sections of the open hole lateral were not contributing to the production due to inefficient distribution of acid across the lateral. Hence there was a need for a completion system which could target those unaccessed, relatively low permeable and untreated zones by providing positive mechanical diversion. With this completion technology, formation treating fluids can be pumped effectively and at maximum desired rates. As a part of the ongoing production strategy, Open Hole Multistage Completion (OHMSC) systems consisting of multiple frac sleeves flanked by open hole packers were deployed in multiple appraisal wells and achieved higher productivity in reduced time. This paper will present details on challenges encountered during wellbore preparation and techniques implemented to deploy OHMSC system in Minagish field. The lessons learnt after executing the project and performance improvement to encounter more challenging reservoir and hole conditions in future are discussed in detail.
Al-Muhanna, Danah (Kuwait Oil Company) | Ahmed, Zamzam (Kuwait Oil Company) | Al-Qallaf, Aliah (Kuwait Oil Company) | Ajayi, Ayo (Shell Upstream International) | Al-Othman, Mohammad (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Al-Salali, Yousef (Kuwait Oil Company) | Al-Ajmi, Moudi (Kuwait Oil Company)
Abstract Jurassic Gas Field Development Group (GFDJ) of Kuwait Oil Company (KOC) completed the first ever CO2 foamed acid frac pilot campaign in four Jurassic sour HTHP wells. This innovative technology was utilized for the first time in KOC's history safely and effectively with exemplary well performance. GFDJ had been pursuing the CO2-foamed acid fracturing technology since 2019 with the objective of improving the stimulation and hydraulic fracturing efficiency in the Jurassic Middle Marrat formation. CO2-foamed acid fracs have several advantages over other stimulation techniques: CO2 is a miscible and non-damaging fluid which blends in water and also mixes with hydrocarbons. Pumped as a liquid and slightly heavier than water, leading to lower treating pressures due to heavier hydrostatic head. Effective in treating lower-pressured/partially-depleted, good K.H (permeability-height function) carbonate reservoirs. Reduces water-based gels and overall frac-load volume by the percentage of CO2 pumped in the frac fluid system (40% by volume is utilized in this pilot). Energizes the frac fluid and stays in solution until it heats up to gas. This property ensures the frac load recovery is achieved throughout the flowback. Eliminates the need to activate the well after the frac with CT/N2 applications potentially saving time and money to KOC. Has potential to lighten up the heavier ends of the hydrocarbons due to its miscible properties, hence may help with better hydrocarbon inflow. Creates stable foam structure with the frac fluid, increasing the frac fluid viscosity hence has the potential to generate better frac geometry and larger stimulated rock volume (SRV). A four-well campaign was completed within 12 months period. Three different monobore completion wells and one 3-1/2″ tubing with 5″ liner completion well were fracture-treated using an average of 40% downhole quality CO2-foam pumped at an average rate of 30 bpm. Different service companies and their fluid systems, as well as their operational capabilities were utilized in operations with exemplary clean up and production test results that surpassed the expectations of the asset. Additionally, pumping cryogenic CO2 at high ambient desert temperatures of September in Kuwait, safely, and operationally effectively is a major milestone and achievement in itself. This paper summarizes the design, operational, well clean-up and production performance details of the CO2 campaign. Learnings of the GFDJ asset will be shared in order to benefit from the learning curve that KOC went through in implementing this strategic application. Success of novel CO2 stimulation technique is critical for the GFDJ asset to continue expanding its production capacity in next 2-3 years while maintaining the strong production plateau achieved in 2021. Future plans of the assets will also be discussed to ensure cross-boundary opportunity realization will be possible in the industry for the region.
Al-Muhanna, Danah (Kuwait Oil Company) | Ahmed Abdul-Samad, Zamzam (Kuwait Oil Company) | Al-Qallaf, Aliah (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Al-Awadhi, Mansour (Kuwait Oil Company) | Al-Salali, Yousef (Kuwait Oil Company) | Abdel-Basset, Mohamed (Schlumberger)
Abstract The first ever CO2 foam fracturing new technology in Kuwait Oil Company (KOC) history was executed flawlessly in late 2021. Three treatments were executed. Co2 Foam Fracturing proved its significant added value of improving productivity in deep depleted tight carbonate Jurassic reservoirs, enhance flow back, reduce water consumption and carbon emission, and enable early production plus improving operation efficiency and cost saving. The stimulation operation has proven to be a huge success for all multidisciplinary teams involved as preliminary results showed over 50-70% production increase compared to offset wells. The main challenges of acid fracturing stimulation in depleted reservoirs are the need for extended formation cleanup to flow back the injected fluids via prolonging Nitrogen lift that add higher operational costs and intervention operations. Therefore, energetic high foam efficiency frac fluid becomes essential to assist flowback and retrieve pumped frac fluids from reservoir. To tackle these challenges, Carbon Dioxide CO2 is pumped in liquid phase as energetic fluid together with normal frac fluids. Due to CO2 liquid nature, high foam efficiency can be reached (40 – 50%) at much lower friction losses. So, it enables achieving pumping frac at high rates and high foam efficiency. The main benefits of CO2 Foam frac are better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and the increase in hydrostatic pressure while pumping that translates to lower surface pressures during injection. The selected pilot well is in depleted deep tight carbonate reservoir area of North Kuwait Jurassic gas fields. The executed acid fracturing operation required close planning starting from Q1-2021. Many challenges faced from logistical issues, lack of infrastructure and CO2 resources for the multi-faceted operation due to COVID-19 pandemic limitations. These challenges were tackled ahead with the integration of technical and operations teams to bridge the knowledge gap and to enable executing the operation safely. The pilot well's net incremental production gain is estimated at 50-70% compared to offset wells, with improved flowback and formation cleanup with less well intervention. The resulting time and cost savings as well as the incremental well productivity and better operation efficiency confirmed high perspectives for the implemented foam acid fracturing approach. Another two CO2 Foam acid fracturing wells were executed with good results too. This paper will demonstrate the value of CO2 foam fracturing in depleted reservoir and KOC experience post first application and its plans to expand CO2 Foam Fracturing application across KOC different fields.
Qubian, Ali (R&T Subsurface Team of Innovation & Technology Group – Kuwait Oil Company) | Zekraoui, Mohammed Ahmad (R&T Subsurface Team of Innovation & Technology Group – Kuwait Oil Company) | Mohajeri, Sina (Energy Technologies - Target Energy Solutions L.L.C) | Mortezazadeh, Emad (Energy Technologies - Target Energy Solutions L.L.C) | Eslahi, Reza (Energy Technologies - Target Energy Solutions L.L.C) | Bakhtiari, Maryam (Energy Technologies - Target Energy Solutions L.L.C) | Al Dabbous, Abrar (R&T Subsurface Team of Innovation & Technology Group – Kuwait Oil Company) | Al Sagheer, Asma (R&T Subsurface Team of Innovation & Technology Group – Kuwait Oil Company) | Alizadeh, Ali (Energy Technologies - Target Energy Solutions L.L.C) | Zeinali, Mostafa (Energy Technologies - Target Energy Solutions L.L.C)
Abstract Reservoir simulation is the main factor in decisions made by oil companies in reservoir management. However, the simulation of huge and complex oil reservoirs through a time-saving and high-accuracy method is the primary concern in reservoir simulation. In this study, a novel AI-Physics hybrid model was proposed for combining with the traditional reservoir simulation to overcome the time-intensive history matching challenges. A combination of classical numerical simulation and deep learning neural network was applied to train the hybrid model with historical data. As a result, a model was obtained with predictive capabilities to forecast the field's behavior. Then, we combined AI-Physics history training with blind test prediction calculation of remaining oil maps. Finally, forecast scenario definitions based on the remaining oil map were created by the AI-Physic model. The proposed novel simulation method can reduce the history matching and scenario assessment time by 90 to 95%. According to its capabilities, three improved forecast scenarios were created based on a predefined scenario. These improved scenarios can produce a significant million standard barrels more oil than the original development scenario within three years. This technology eliminates limitations for multiple scenario assessments. In our AI hybrid model, the power of dynamic reservoir simulation is combined with a modern machine learning approach to "Evergreen" forecasts in reservoir assets. Consequently, the simulation resulted in a sub-optimal shortcut between model updates and inconsistencies in production forecasting. Moreover, applying deep learning methods to focus on the critical reservoir properties intelligently leads to tremendous time-saving in the static model update life cycle. In fact, with this novel simulation that we implemented, the new production data could be incorporated within minutes to regenerate more reliable and up-to-date forecasts. This simulation generates ‘up-to-date’ remaining hydrocarbon maps interactively, so the operator can continuously optimize the infill drilling locations between Field Development Plan (FDP) cycles.
Abdulkarim, Anar (Halliburton) | Kharitonov, Alexander (Halliburton) | El Gezeery, Taher M. (Kuwait Oil Company) | Haddad, Mohamed Al (Kuwait Oil Company) | Halawah, Yousif Ahmad (Kuwait Oil Company) | Sabea, Salem Al (Kuwait Oil Company)
Abstract The Wara sandstone reservoir in the Minagish field of Kuwait Oil Company is a complex deposition of a typical pro-deltaic environment consisting of shaly-silty sandstone sequences W7-W1. Three sequences (W6, W5, and W3) were expected in the case study well. The objective was to set 9⅝-in. casing at the top of W6 and then drill through the Wara sequences to connect all of them and land and drill the lateral section within W3. The W6 sequence is typically the primary target in the Wara formation, being thick and consistent throughout the field. The next logical step in developing the Wara reservoir was to study and investigate the minor W5 and W3 members. Due to poor correlation of W5 and W3 channels in offset wells, the geological target was selected based on seismic Poisson impedance. Historically, targeting the Wara formation occasionally resulted in multiple sidetracks due to drilling challenges. A real-time geomechanics service was utilized to overcome drilling challenges and real-time 3D ultra-deep resistivity inversion was implemented to optimize well placement. An extensive pre-drilling study for geomechanical and ultra-deep resistivity inversion modelling helped to develop road map for an optimal and safe well-construction process. The study showed that utilization of real-time 3D ultra-deep resistivity (UDR) inversion would help to optimize well placement and maximize sweet-zone exposure. The original well design, mud properties, and drilling parameters were modified based on the geomechanical study. Additionally, real-time geomechanics services were utilized to monitor and control the drilling process to follow the road map, which helped to avoid drilling issues, geostop at the W6 channel, and finally to run the casing smoothly. Real-time 3D ultra-deep resistivity mapping in the lateral section helped the operator to drill through W6 and W5, land precisely, and drill the lateral in the W3 channel, which was well developed, as expected from seismic Poisson impedance analysis. Formation evaluation of lateral section showed an average porosity of 24 p.u., water saturation 11% and up to 3 D/cp mobility. The application of real-time 3D ultra-deep resistivity inversion helped to triple the planned formation exposure and to discover a geometric extension of the above deposited channels (W6 and W5), which will help for future field development. The flow test showed the highest production rates from W3 of the field. The integrated approach described above was recommended to be utilized for all future Wara wells.