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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Abstract The oil and gas industry face unprecedented challenges and opportunities which demand innovative solutions. There needs to be more than the traditional centralized IT operational model to meet the dynamic needs of the industry. This has led to new models, such as the citizen developer program, which enables business users to create and deploy applications without requiring specialized technical skills. The citizen developer program is a new approach allowing non-IT professionals to create applications for their business needs using low-code and no-code platforms. This program aims to decentralize IT operations, increase innovation, reduce costs, and enhance customer experience. The democratization of technology is the core concept behind the citizen developer program, which enables businesses to create their applications and automate their processes . The implementation of a citizen developer program requires careful planning and consideration of various factors, including change management, awareness and marketing of the concept, training, selecting the correct low code no code tool, management buy-in, building a community of practices for citizen developers, governance/policy, and more. These elements are critical to the program's success and must be carefully considered during implementation. This manuscript provides a framework for implementing a citizen developer program in the oil and gas industry. It also includes a case study of implementing such a program and creating significant value in Kuwait Integrated Petroleum Industries Company (KIPIC). The Framework emphasizes the importance of change management, awareness and marketing of the concept, training, selecting the correct low code no code tool, management buy-in, building a community of practices for citizen developers, governance/policy, and more. The manuscript aims to provide insights into the benefits of implementing a citizen developer program in the oil and gas industry and its potential impact on the IT operational model. In summary, the citizen developer program represents a paradigm shift in the oil and gas industry, which enables businesses to create and deploy applications without relying solely on IT professionals. This program can increase innovation, reduce costs, and enhance customer experience. The implementation of a citizen developer program requires careful planning and consideration of various factors, as outlined in this manuscript.
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.
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.
Elgaddafi, R. M. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Al Saba, M. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Almarshad, A. (Kuwait Institute for Scientific Research, Kuwait City, Kuwait) | Amadi, K. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait)
Abstract In meeting the world's climate-change goals, the oil and gas industry will have to play a significant part, although the specific initiatives chosen to reduce the emissions may vary, re-engineering waste products that contribute to carbon emission into useful recyclable products for the oil and gas industry can significantly contribute to developing a circular economy and sustainable environment. This study considered recycling finely ground auto-tire rubber as an effective drilling fluid additive. Waste tire, which is a major air pollutant when burned, was collected from a national recycling company. A laboratory study of using the finely ground auto-tire rubber waste as an effective fluid loss control and bridging additive was performed and compared with sized graphite, which is a commonly used bridging material in the industry. A commonly used water-based drilling fluid formulation was employed as a base fluid for all the experiments. The performance of the drilling fluid containing the waste auto-tire finely ground rubber was assessed by conducting standard rheological measurements and API fluid loss, where concentrations ranging between (0.0 – 10 lb/bbl) were added to the base fluid. The effect of adding the waste auto-tire rubber on plastic viscosity, yield point, apparent viscosity, and fluid loss was assessed. In addition, the possibility of replacing the sized graphite with the proposed material was investigated. The results showed a significant reduction in a fluid loss by up to 23% by the addition of (10 lb/bbl) of finely ground auto-tire rubber waste to the base fluid (containing 5% bentonite). Furthermore, analysis of the test measurements showed a minor to negligible effect on the rheological properties compared to the base fluid. Also, it revealed that waste auto-tire finely ground rubber can successfully functionalize as a fluid loss additive and completely replace sized graphite as a bridging material, where replacing the sized graphite with the proposed material resulted in a reduction in the fluid loss of up to 21%. The promising results obtained in this study highlight the huge potential for this initiative in utilizing recycled auto-tire waste materials as a possible drilling fluid additive and demonstrate a sustainable technique with large-scale application in the oil and gas field whilst reducing solid waste disposal and consequent CO2 emissions resulting from burning waste tires.
Ekpe, J. (KOC Kuwait Oil Company) | Al-Shehab, A. (KOC Kuwait Oil Company) | Al-Othman, A. (KOC Kuwait Oil Company) | Baijal, S. (KOC Kuwait Oil Company) | Marin, G. (Weatherford) | Benyounes, H. (Weatherford) | Aliyeva, A. (Weatherford) | Alqabandi, R. (Weatherford) | Selami, B. (Weatherford) | Al-Fakeh, B. (Weatherford)
Abstract The development of Najmah-Sargelu (NJ-SR) limestone fractured reservoir, has a significant role in Kuwait Oil Company (KOC) 2040 strategy. To achieve this objective, hydrocarbon potential across the NJ-SR reservoir will have to be evaluated in the West Kuwait of Kra Al-Maru (Figure 1). First and foremost, this section will have to be drilled to planned section TD, cased off and successfully cemented. This paper discusses KOC experiences and best practices implemented to ensure utilizing managed pressure drilling equipment to achieve a successful 7-5/8-in liner cement job at well depth of 16,945ft. MD (15,756ft. TVD), and reservoir pressure and temperature ranges of 12,000 - 15,000psi and 230 - 280 deg F respectively. This new approach to cementing is based on Managed Pressure Drilling technology. It addresses running the 7-5/8- in liner and cementing it in MPD mode. A step-bystep procedure is provided that ensures a constant bottom pressure is maintained throughout the process. Risk assessment showing what can go wrong and mitigations are provided, and the method is described in detail to allow readers comprehend the unique case presented in this paper. Managed Pressure Cementing (MPC) technique in case study well is compared to offset wells in West Kuwait Field where cementing was conducted conventionally. In most cases, the cement bond logs show cement dispersed throughout the annulus with no continuous bond - channels in the cement behind the casing. The most significant new findings from this paper are that, in a couple of wells where there were no losses while pumping cement conventionally- the cement bond logs showed moderate to poor cement behind casing and channels within the cement. This technology offers opportunity to achieve good cement bonding with liner in fractured limestone which can be problematic due to the risk of losses and the presence of hydrocarbons with high pore pressure in West Kuwait NJ-SR intervals. This novelty approach using Managed Pressure Cementing technique to case and cement liners in West Kuwait fields and tight margin reservoir will ensure good cement bond logs behind casing and improve well testing and completions strategies.
Nour, Ahmed (Kuwait Oil Company, Kuwait City, Kuwait) | Al-Suwailem, Lulwa (Kuwait Oil Company, Kuwait City, Kuwait) | Al-Jutaili, Dalal (Kuwait Oil Company, Kuwait City, Kuwait) | Monteiro, Ken (Kuwait Oil Company, Kuwait City, Kuwait) | Al-Safran, Sarah (Kuwait Oil Company, Kuwait City, Kuwait) | Bogaerts, Martijn (SLB, Abu Dhabi, United Arab Emirates) | Aiman Fituri, M. (SLB, Kuwait City, Kuwait) | Oostendorp, Mischa (SLB, Kuwait City, Kuwait) | Khalil, Mohamed (SLB, Doha, Qatar)
Abstract Removing mud from around the casing or liner and replacing it with drilling or cement fluid is fundamental to achieving zonal isolation. One significant parameter needed to achieve flow around the casing is proper casing centralization. Casing centralization is a function of many wellbore properties, such as fluid and centralizer data, which are obtained from the directional survey and caliper data. Computer simulations are used to optimize centralizer selection and placement prior to running the casing into the wellbore and the cementing operations. This paper presents the method and technology used to compare simulated vs. real centralization and the key lessons learned from a Kuwait project. To complete the continuous improvement cycle, it is important to confirm the casing standoff in a postcement operation to determine if the prejob assumptions and the simulations were accurate. Using standard cement evaluation logs, it is not possible to directly measure the casing standoff. Therefore, conclusions have to be made indirectly, based on the cement evaluation data. The new-generation ultrasonic flexural measurement tools can be used to evaluate casing centralization directly by evaluating the time between the first casing reflection (mud to casing interface) and the third reflection (cement formation interface). For a Kuwait project, a new one-piece slip-on centralizer was introduced for field operations. Prejob standoff simulations were performed to optimize the casing standoff to meet the operator and service company recommendations. All available well and fluid data were included in the simulations to accurately predict the casing standoff. The simulations used a state-of-the-art, stiff-string simulator to provide the most accurate simulations results. To evaluate the standoff simulations and centralizer performance, the third-interface echo (TIE) measurements were used to determine actual standoff. The ultrasonic measurements were run on three different cemented intervals. These intervals ranged from a vertical 16-in open hole interval to a highly deviated 8½-in openhole section. By comparing the actual measurement with the simulations results, a direct standoff evaluation was made possible regarding the centralizer selection and placement and the assumptions made during the well planning phase. It also provides better understanding on the performance of the centralizers. Using the advanced flexural ultrasonic logging tool and the TIE measurement provided the opportunity to compare actual casing standoff results vs. prejob casing centralization simulation. The results demonstrated the importance of having accurate well data available during the design phase and the impact particular assumptions have on the final casing standoff. By comparing the actual casing standoff results vs. prejob casing centralization simulation, important lessons can be learned about centralizer selection, placement, and how standoff simulations can be implemented during field development to improve casing standoff. Thus, the probability of effective mud removal and zonal isolation increases.
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
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.
Abstract With the emerging necessity of carbon capture and storage (CCS), many companies are evaluating the possibilities of CCS implementation in their assets. Technical evaluation for converting existing fields to CCS projects includes various topics such as carbon dioxide (CO2) transportation and its economics among other topics. Selecting a method for CO2 transportation becomes important when the target site is distant from the CO2 source, particularly if located offshore. The Intergovernmental Panel on Climate Change (IPCC) special report on CCS has identified that a liquefied CO2 (LCO2) carrier would be the lowest-cost option for distances more than 1700 km. An LCO2 carrier can also be the best option when transporting CO2 abroad to benefit from the international carbon tax, which has been collecting global interest. Along with this increased interest in LCO2 carriers, shipbuilding and engineering companies are developing their ships. When an LCO2 carrier is used for offshore CCS, the ship would be located right above the target site to minimize the length of pipelines. As this distance between the LCO2 carrier and the target reservoir is shorter than other transportation options, the traditional modeling approach uses a standalone model of the LCO2 carrier. This approach excludes pipeline models when estimating required operating conditions of the carrier assuming a fixed outlet boundary condition. However, this boundary condition may differ from the actual value. Furthermore, in real systems, operating conditions (i.e., pressure and temperature) are not constant over time. Ignoring the dynamic interaction with downstream pipelines may lead to subsequent differences in simulation results. The actual thermo-hydraulics behavior of LCO2 carrier cannot be reproduced when standalone models are introduced. In this study, a standalone LCO2 carrier model and an integrated dynamic CCS model connecting the LCO2 carrier, injection equipment, riser, pipeline, and wellbore were developed. The standalone LCO2 carrier model predicts the behavior of a whole ship from two LCO2 tanks to the carrier's outlet, which would be connected to the riser of the CO2 injection system. The integrated model calculates the whole CO2 injection system from two LCO2 tanks to the target reservoir by linking the standalone LCO2 carrier model and a flow model starting from the riser to the injection wellbore. The simulation results showed that the required CO2 pump discharge pressure of the integrated model was 5 bar higher than the standalone model to meet the target flow rate. As the required discharge pressure increased, the average speed and power consumption of the CO2 pump increased by 2.5% and 7%, respectively. In this comparison study we demonstrated that the integrated model could accurately represent the overall system behavior. No risk of solid CO2 formation was identified during unloading of two LCO2 tanks. By using the developed integrated model, three different case studies were conducted to analyze the effect of rigorous heat transfer in LCO2 tanks, simultaneous tank unloading, and initial startup operation on the thermal-hydraulic performance of the system, respectively. The first case demonstrated that modeling the tanks with high-thickness thermal insulation is close to an adiabatic condition. The required discharge pressure of the CO2 pump was the same, and the final pressure and temperature of the tank holdup increased by 1 bar and 2°C, respectively. The second case showed that changing the operation from sequential to simultaneous unloading of the two LCO2 tanks removed the disturbances observed during the transition of tanks in the sequential case. This removes potential instabilities in the pump controller and avoids any impact on the injection system performance. The unloading time was only 20 seconds shorter, and the required pump discharge pressure was the same. The third case demonstrated that the integrated model could analyze the initial startup operation, which displaces nitrogen (N2) and methane (CH4) in the pipelines and wellbore with CO2, which standalone models cannot predict. It took 500 seconds to fully displace N2 and CH4 in the system with CO2. Furthermore, the required valve opening time (19 seconds after injection commences) to prevent backflow from the reservoir could be determined. In conclusion, dynamically integrated modeling can help identify interactions that are not apparent in the traditional standalone modeling approach. The integrated model can evaluate system behavior and possible operational risks that cannot be observed in standalone models. Simulation results in this work demonstrated that the dynamically integrated CCS model captures more realistic behavior of the whole CO2 injection system to help optimize the design and operation of a CCS project. Developing a plan to address these interactions through the integrated dynamic simulation can result in a more stable operation.
Gandomkar, Asghar (Department of Chemical and Petroleum Engineering, Faculty of Engineering, Shiraz Branch, Islamic Azad University (Corresponding author)) | Torabi, Farshid (Faculty of Engineering and Applied Science, University of Regina) | Nasriani, Hamid Reza (School of Engineering, Faculty of Science and Technology, University of Central Lancashire) | Enick, Robert M. (Department of Chemical and Petroleum Engineering, University of Pittsburgh)
Summary In this study, the ability of dilute concentrations of toluene to act as a CO2-soluble asphaltene stabilization agent capable of inhibiting asphaltene precipitation during immiscible CO2 injection was assessed. Phase behavior results indicated that 1,000 to 20,000 ppm toluene could readily dissolve in CO2 at cloudpoint pressures that are well below the formation pressure and typical CO2 minimum miscibility pressure (MMP) values during gas-based enhanced oil recovery (EOR). Single-phase solutions of the modified gas (CO2/toluene) were then combined with asphaltenic oils in oil swelling phase behavior tests to demonstrate that the presence of toluene increased the amount of CO2 that dissolved into reservoir crude oil at a specified temperature and pressure. However, asphaltene precipitation diminished, apparently because the effect of the increased asphaltene solvent strength of toluene was more significant than the increased amount of CO2 (an asphaltene antisolvent) that entered the oil-rich phase. During the injection of CO2/toluene solution into cores initially saturated with crude oil and brine, compared to the injection of pure CO2, asphaltene deposition declined during the injection of CO2/toluene mixtures for asphaltenic volatile and intermediate oils from 3.7 wt% to 0.7 wt% and 5.9 wt% to 1.7 wt%, respectively. Based on the asphaltene particle-size analysis, the CO2/toluene mixtures can stabilize oil particles and simultaneously reduce asphaltene aggregation more effectively than pure CO2.