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Al Khalifa, Nasser (KOC) | Hassan, Mohammed (KOC) | Joshi, Deepak (KOC) | Tiwary, Asheshwar (KOC) | Al Shammari, Yousef Suhail (KOC) | Clegg, Nigel (Halliburton) | Clarion, Benjamin (Halliburton) | Kharitonov, Alexander (Halliburton) | Pan, Li (Halliburton)
Through decades of production and water injection, Umm Gudair reservoir fluid distribution have changed significantly, resulting in an increase of uncertainties on fluid levels and subsequent water cuts in production. Different well architectures have been implemented pilot holes, deviated wells or horizontals, but the development of such mature fields comes with inherent difficulties, as offset data does not necessarily reveal the current reservoir properties and fluid contact position. Frequently, costly and time-consuming additional operations such as cement plugs or sidetracks are required to resolve an unforeseen water saturation of the reservoir. However, these methods have a limited efficiency in reducing the water percentage over the time of well production.
In this challenging environment, the Umm Gudair asset has implemented a different approach to well construction built upon the combination of an ultra deep resistivity tool with a previously unattempted benchmarking scenario for a look around inversion. Drilling a trajectory of 45° inclination in order to proactively identify the oil water contact (OWC) in the far field below, and confirm this forecast with an actual resistivity measurement during its penetration. This unprecedented process shows great opportunities in optimizing future well placement and production performances. The main inputs in this success come directly from the capability of the inversion of the electromagnetic measurements in various drilling conditions, as well as a thorough preparation and collaboration between the operator and the service company.
Before implementing this technology, it is critical to assess the expected performance by understanding the different parameters which affect the performance of the tool. The study of the different offsets gave an overview of potential resistivity contrast between fluids and their contact positions. The pre-well study is therefore essential to optimize depth of detection (DOD) versus sensitivity through forward modeling of various frequencies and spacing selections. This phase is also necessary for the team to understand what can be expected from the service with the elaboration of different scenarios based on theoretical tool responses and communication protocol.
This case study shows how an innovative scenario and collaboration between operator and service company reveals a new capability to place a well drilled at mid-angle in the lowest water saturated part of the reservoir using inverted resistivity measurements. The economic benefit and post job analysis conducted post well confirm the promising outlooks of utilizing an ultra-deep resistivity service in a mature field environment.
It is imperative to produce very high GOR wells to sustain production from matured fields. ESP and PCP are major lift modes in KOC. These lift systems can handle up to 50% of free gas, when used along-with standard gas separators. Therefore, there is a need for advanced lift systems, which can help to sustain production and run-life of equipment, when free gas at pump intake is more than 50%. Objective of the present work is to share our experience, with regard to evaluation and implementation of suitable ESP and PCP systems to produce very high GOR wells.
In this regard, study of suitable ESP and PCP systems, which can handle very high gas rates, is done. Based on this study, two technologies, namely, ‘ESP with advanced down-hole multiphase gas handler’ and ‘PCP system, designed to handle very high gas rates’, are considered for pilot implementation. Both these systems are capable to handle 75% of free gas. Suitable candidate wells, where envisaged free gas at pump intake is more than 50%, are selected for these pilots. Performance of these lift systems are monitored during the pilot period and results are analyzed.
Candidate well selected for the pilot of ‘ESP with advanced down-hole multiphase gas handler’, was on self-flow, before installation of this system, with an oil rate of 600 b/d and GOR of 750 scf/barrel. The system has performed exceedingly well during the pilot period of 6 months and peak oil gain of 1100 b/d, is recorded during the pilot. Candidate well selected for the pilot of ‘PCP system, designed to handle very high gas rates’, was not flowing, before installation of this system. Estimated GOR is 900 scf/barrel. Excellent system is performance is observed during the pilot period of 6 months. Peak oil gain of 500 b/d, is reported during the pilot period.
The study enlightens efficacy of these specific lift systems to enhance or sustain production on long-term basis, under high GOR environment. Both these lift systems can be used for efficient exploitation of mature fields. The study can serve as a valuable reference for all operators, for production of very high GOR wells, which need either ESP or PCP, as a lift mode.
Abstract Workover operations in shallow low pressure heavy oil unconsolidated sandstone reservoir in Kuwait presents a major challenge due to significant killing fluid loss which causes wellbore plugging, incremental operational costs due to more rig days, excess brine volumes, and more importantly the impact of deferred production due to formation damage. This paper presents an innovative fluid-loss control pill added to killing fluids, which has resulted in significant cost savings and well productivity improvements. The subject heavy oil reservoir have formation pressure equivalent to 6.3 PPG versus 9.3 PPG Potassium Chloride brine used as killing fluid. This overbalance condition is a requirement as safety barrier but conversely it leads to hundreds of barrels of killing fluid losses with the consequently invasion and formation damage. Kuwait Oil Company recently added a new customized fluid loss control pill of high purity vacuumed dried evaporated salt to the well killing procedure. Using this fluid loss control pill both drilling and reservoir engineers achieved their aim in terms of safety operation and no formation damage. To test this new pill, two shallow wells with 220 psi reservoir pressure and perforation set at 630 ft were selected to record the losses. The first well had undergone workover including recordings from caliper, cement, and ultrasonic logs, which measured the positive impact of the new control pill on logs quality by excluding fluid pumping while logging and having constant fluid level at surface, which saved cable head from unnecessary tensions. In a second well, there was hanged standalone screen on a packer against the perforation and there is no direct access to the perforation. The control pill was customized to be pumped into the screen, which sealed the screen itself perfectly. The control pill flowed back easily in both wells and same loss rate was observed after removing the pill, which confirmed no negative impact on reservoir permeability. KOC confirmed that the two jobs were successful and the pill to be approved for full field implement in other operations. The achieved success criteria summarized as follows: Hydrostatic column is a safety barrier that assuring fluid level at surface during workover is safety requirement especially in high Gas oil ratio wells. Full circulation enhances sand cleanup operation. Fluid level at surface results in accurate logging by eliminating invasion into reservoir and support improved operations.
Dean, Elio (Surtek, Inc.) | Pitts, Malcolm (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.) | James, Dean (Surtek, Inc.) | Mills, Kathryn (Surtek, Inc.) | Al-Murayri, Mohammed (KOC) | Al-Kharji, Anfal (KOC)
With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field.
Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery.
Analysis concludes the following:
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion.
Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects.
Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil.
Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.
Summary Flow zonation and permeability estimation is a common task in reservoir characterization. Typically, integration of openhole log data with a conventional and special core analysis solves this problem. We present a Bayesian‐based method for identifying hydraulic flow units in uncored wells using the theory of hydraulic flow units (HFUs) and subsequently compute permeability using wireline log data. We use a nonlinear optimization scheme on the basis of the probability plot to determine pertinent statistical parameters of each flow unit. Next, we couple these results with the F‐test and the Akaike's criteria with the purpose of establishing the optimal number of HFUs present in the core data set. Then, we allocate the core data into their respective HFUs using the Bayes’ theorem as clustering rule. Finally, we apply an inversion algorithm on the basis of Bayesian inference to predict permeability using only wireline data. We illustrate the application of the procedure with a carbonate reservoir having extensive conventional core data. The results show that the Bayesian‐based clustering and inversion technique delivers permeability estimates that agree with the core data and with the results obtained from a pressure transient analysis.
Flow zonation and permeability estimation is a common task in reservoir characterization. Typically, integration of openhole log data with a conventional and special core analysis solves this problem. We present a Bayesian-based method for identifying hydraulic flow units in uncored wells using the theory of hydraulic flow units (HFUs) and subsequently compute permeability using wireline log data.
We use a nonlinear optimization scheme on the basis of the probability plot to determine pertinent statistical parameters of each flow unit. Next, we couple these results with the F-test and the Akaike’s criteria with the purpose of establishing the optimal number of HFUs present in the core data set. Then, we allocate the core data into their respective HFUs using the Bayes’ theorem as clustering rule. Finally, we apply an inversion algorithm on the basis of Bayesian inference to predict permeability using only wireline data.
We illustrate the application of the procedure with a carbonate reservoir having extensive conventional core data. The results show that the Bayesian-based clustering and inversion technique delivers permeability estimates that agree with the core data and with the results obtained from a pressure transient analysis.
Al Matar, Mohammed (KOC) | Mohapatra, Samarendra (KOC) | Al-Ateeqi, Hamad (KOC) | Gaur, Rishika (Halliburton) | Chawla, Sapna (Halliburton) | Khandelwal, Nakul (Halliburton) | Almesfer, Mohammad (Halliburton) | Gorgi, Sam (Halliburton)
Abstract Increasing water cut and well integrity are currently major concerns, particularly in mature fields. Excessive water production can detrimentally affect the profitability of hydrocarbon-producing wells if not controlled properly. This paper describes a successful zonal isolation case study in a dual-string completion well with well integrity challenges and variable permeability intervals using a modified organically crosslinked polymer (m-OCP) and coiled tubing (CT)-assisted real-time temperature sensing for effective placement and post-operation evaluation. The m-OCP system is a combination of a thermally activated, organically crosslinked polymer and particulate material for leakoff control to help ensure shallow matrix penetration. It is acid resistant, H2S tolerant, has controlled penetration, and is easy to clean up using a rotating wash nozzle. The setting time can be accurately predicted with simple laboratory tests. These characteristics make this system the preferred choice compared to the traditional cement squeeze method that is both time consuming and exorbitant. Diagnostic services delivered by CT-conveyed fiber-optic distributed temperature sensing (DTS) that add real-time capabilities to monitor well integrity assess reservoir performance and visualize treatment efficiency. Using real-time diagnostic services, tubing integrity was confirmed, and the treatment was placed in the same run, helping eliminate the possibility of an undesired leakoff. After allowing the setting time, a successful pressure test or post-cleanout DTS (in case pressure test is not feasible) was used to establish the reliability of this method. The first attempt was made on Well A of the field; however, isolation was successful using m-OCP and conventional CT. Operation execution and production recovery took more time than planned because of the uncertainty concerning well integrity in the dual-string completion and lost circulation in the depleted reservoir, which affected the economic deliverability of the operation. The major challenges with Well B of the same type in the same field remain the same. Thus, as part of lessons learned from the previous intervention, diagnostic services were chosen for a real-time evaluation of the completion to review well integrity and accurately place the optimized treatment, thereby helping improve overall results in the most time-saving and lucrative manner. The successful isolation of the water-producing zone/perforations in the southeast Kuwait field using m-OCP and CT-assisted real-time DTS to review well integrity can be considered a best practice for addressing similar challenges globally.
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Jassim, Sara (KOC) | Snasiri, Fatemah (KOC) | Al-Nasheet, Anwar (KOC) | Al-Mansour, Yousef (KOC) | Ali, Abdullah (NAPESCO) | Sheikh, Bilal (NAPESCO)
Asphaltenes flow in equilibrium with the liquid phase as other components of the produced hydrocarbon. If asphaltenes are in solution during production, there are not negative impact to well productivity. However, asphaltenes could precipitate as pressure, temperature and composition change. If precipitated, due to pressure decrease, asphaltene could deposit as a solid phase in the formation rock near wellbore becoming an obstruction to flow and inducing formation damage. Skin due to asphaltene deposition near wellbore was confirmed in several wells of a carbonate reservoir. Asphaltene deposition was also observed in the production tubing. The objective of this work is to investigate the main variables affecting asphaltene deposition in the Magwa-Marrat field is South East Kuwait and develop a technique to manage and/or decrease formation damage due to this solid deposition phenomena. In order to estimate the skin value and predict the location of any impairment to production, a pressure gauge was set at 1,000 ft above the top of the perforations and the well was equipped with a permanent multiphase meter device. A series of pressure buildup tests and multi-rate tests were run to disseminate Darcy skin from non-Darcy skin. Pressure transient analysis (PTA) delivered total abnormal pressure losses from the formation near wellbore to the gauge location, while multi-rate tests (MRT) allowed to investigate rate dependent skin. Well tests at different rates were also run to investigate the relationship between fluid velocity and asphaltene deposition. Once the elements of total skin were split into Darcy skin and Non-Darcy skin, a tubing clean-out and a stimulation job were designed and implemented to eliminate the asphaltene deposits and remove the damage. Total skin was reduced from +30 to −3.5 and productivity index was increased by a factor greater than ten (10). The production rate to mitigate asphaltene deposition was successfully determined. The well has been on production for about 1 year without developing any additional damage and without further deposition of asphaltene in the production tubing as the well has been flown above the minimum flow velocity that would allow asphaltene deposition. A combination of well intervention combined with determination of operating conditions have been developed to successfully produced asphaltenic hydrocarbons at flowing bottom hole pressure (FBHP) below asphaltene onset pressure (AOP). This methodology has been successfully implemented. If the liquid velocity is high enough to carry precipitated asphaltene out, solid deposits are not observed and there is not harm to productivity. The technique has worked for a case where reservoir pressure has been depleted below asphaltene onset pressure (AOP). This is a fundamental change in the globally applied industry approach that urges to produce asphaltenic hydrocarbons at FBHP above AOP.
Hussein, Ahmed (Exprogroup) | Alqassab, Mohammed (Exprogroup) | Atef, Hazem (Exprogroup) | Sirdhar, Siddesh (Exprogroup) | Alajmi, Salem Abdullah (KOC) | Aldeyain, Khaled Waleed (KOC) | Hassan, Mohamed Farouk (KOC) | Goel, Harrish Kumar (KOC)
Abstract Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model". A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization. The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well. The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Altemeemi, Bashayer (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Jassim, Sara (KOC) | Sinha, Satyendra (KOC) | Shaw, Paul (BP Kuwait) | Ghloum, Ebtisam (KISR) | Al-Kandari, Bader (KISR) | Kholosy, Sohabi (KISR) | Emadi, Alireza (Premier Oilfield Group-Corex)
Abstract Asphaltene deposition in reservoir rock is very difficult to remediate. If precipitated, asphaltenes could be trapped in the formation pores, the particles can deposit and plug the porous media reducing permeability. However, it has been hypothesized that precipitated asphaltene could entrain back into the liquid phase if the shear rate is high enough before it is deposited, adsorbed and anchored to the rock. This work intends to evaluate the role of rate in the asphaltene deposition tendency for the asphaltenic Magwa-Marrat reservoir fluid. Precisely, the purpose of this work is to study the effect of production rates and operating pressures on asphaltene deposition in the production tubing and reservoir rock at lab level running Coreflooding tests and at field level producing a well at different rates. This work provides insights into field observations of a trial well producing at a bottom hole flowing pressure below AOP. Several multi rate tests and pressure transient analysis were performed to understand asphaltene deposition in the reservoir near wellbore region and away from the well. Asphaltene deposition in the production tubing was also assessed by means of friction coefficient calculations to better understand the deposition mechanism, especially the roles played by shear rate and pressure. Coreflooding experiments at different flow rates below and above AOP were run after proper characterization of the cores and reservoir fluids. As expected, the laboratory Coreflooding results demonstrated that there were no changes in the cores’ flow capacity whether at low or at high velocities when the pore pressure was kept above AOP. However, when the pore pressure was brought below AOP, Coreflooding tests showed that the higher the velocity, the lower the permeability impairment. This concludes that fluid velocity is an important factor in the asphaltene deposition mechanism. Field tests were also conducted, and the field observations were fully consistent with laboratory results. In the case of asphaltenic crude oils, industry standards recommend depleting the reservoir to pressures no lower than AOP. Based on results of this study, and alternative approach is proposed; basically, depending on the rock-fluid properties and their interaction, it is possible to deplete the reservoir pressure significantly below AOP. Asphaltene deposition is nowadays an area of research and this study has brought some uniqueness to this subject. 1) The laboratory tests were designed together with field tests to confirm the validity of conclusions; 2) It demonstrates that a reservoir can be operated at pressures below AOP and wells produced at higher production rates as a result of operating at higher drawdowns. Altogether, the proposed approach in this paper to mitigate asphaltene deposition maximizes production offtake to the full potential of the wells while optimizing ultimate recovery; 3) Results from these field and laboratory tests have been used for field development planning that would increase the net present value of the project by a) depleting the reservoir pressure below AOP, which increases recovery factor, b) delaying water injection which minimizes CAPEX, and c) decreasing well interventions that minimizes OPEX.