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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)
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.
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.
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)
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.
North Kuwait has a vision to produce about 1 million BOPD within next couple of year. As a part of this strategy, all efforts & opportunities are being synchronized to maximize the production. A serious threat to this plan was confronted by observation of Naturally occurring radioactive materials (NORM) at some of the producers, a new challenge for which the asset did not anticipate or had any plan earlier. The paper proposal covers how this threat was converted into an opportunity. A comprehensive review of the wells with NORM was done to understand the link to specific reservoir related issues or zone's mineralogy. As this kind of production problem has been faced for the first time in North Kuwait, brainstorming and technical pros & cons were investigated with internal as well as external consultants. A due diligence was conducted to existing rules & procedures within KOC and Kuwait. Case histories from different parts of the world were reviewed as to how such issues had been resolved. Measurement of NORM, accuracy & validity was also looked into, which varied from vendor to vendor. Thus the gathered knowledge was shared with all stake holder teams.
As almost 30-40 MBOPD was the locked in potential, fast track actions have been taken to create a contract to manage wells suffering from NORM. After going through a fast track identification of suitable vendor, contract was awarded to one of the international vendor. Accordingly, workover rigs were made ready to handle NORM remediation operations professionally. Simultaneously, technical evaluation of the performance of wells infected with NORM was done to understand the phenomenon and the relationship with the changes in reservoir pressure / stimulation. A workover schedule was prepared and implemented to revive the shut-in production potential to the GCs, resulting in a bump in oil production for North Kuwait. As a result of the strategy adopted, deferment of oil production due to NORM, which hovered to more than 1.5 years in the past, is prevented, thus helping production target requirements for the Asset. Performance evaluation of wells indicated that there is a strong relationship of reservoir pressure and stimulation with the NORM level.
NORM management requires an integrated team approach, ranging from working units to the organization level and a proactive analytical approach to understand the impact of ongoing sub-surface operations on NORM tendencies. The proper understanding and analysis done in overcoming the NORM has aided in enhancing and sustaining the production via having extended productive life for the wells.
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio (BP) | Al-Nasheet, Anwar (KOC) | Gonzalez, Doris (BP) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Muhammad, Yaser (Schlumberger) | Datta, Kalyan (KOC) | Al-Mahmeed, Fatma (KOC)
Sound development plans are based on complex 3-D 3-Phase multimillion grid reservoir simulation models. These models are used to run different scenarios where probability distributions are included to understand the impact of uncertainties and mitigate main risks that could raise during the life of the field. With today's available dominant supercomputers, reservoir engineers have the tendency to undervalue the power of classical reservoir engineering. However, in a fully connected reservoir tank that honors the basis of the material balance equation, material balance technique has been long recognized as a powerful tool for interpreting and predicting reservoir performance by estimating initial hydrocarbon in place and ultimate hydrocarbon recovery under various depletion scenarios. In brief, under the right conditions, material balance technique is a suitable tool for field development planning. The power of material balance to predict long term performance is undisputable, especially in the case of a prevailing uncertainty. This is the case of the Magwa-Marrat field, where the development plan has historically been driven by the potential risk of asphaltene deposition in the reservoir.
The objective of this paper is to show a step by step process to integrate data to build a reliable model using material balance and how this model is utilized to progress a field development plan capable of managing uncertainty and provide the tools to mitigate risk.
Pressure data is obtained from repeat formation tester (RFT), static data from shut-in pressures and reservoir superposition pressures from pressure transient analysis. The average reservoir fluids properties are retrieved from a compositional equation of state based on circa 20 PVT studies.
The material balance model was successfully completed, and the resulting stock tank oil initially in place (STOOP) was compared to volumetric calculations. Solution gas, rock compaction and aquifer influx were determined as drive mechanisms. The Campbell Plot, diagnostic tool, was proven to be prevailing defining early energy to determine STOOIP and the aquifer properties were calculated by matching the distal energy
The material balance model was then used to run different development strategies. This methodology captured the impact of depleting the reservoir down to Asphaltene Onset Pressure (AOP) as well as below AOP. The model was also used to define the requirements for water injection rates and startup of a water flooding project for pressure support. Additionally, the material balance work was implemented to support reservoir management and to maximize recovery factor.
This paper presents an innovative approach of integrating asphaltene behavior from laboratory tests and fluid studies, combined with material balance to screen development scenarios for an efficient depletion plan including water injection to manage asphaltene risks and optimize ultimate recovery. Finally, a fully ground-breaking strategy, not reported earlier to the knowledge of the authors, has been established to manage the perceived main risk in the Magwa-Marrat reservoir.
Sanyal, Arunava (KOC) | Kumar, Sanjeev (KOC) | Al Awadh, Ahmed (KOC) | Al Samhan, Sarah (KOC) | Al Azmi, Jassim (KOC) | Sikdar, Koushik (Schlumberger) | Sultan, Gamal Ali (Schlumberger) | Das, Sourav (Schlumberger)
Zubair Formation is one of the key producers in North Kuwait; however, the reservoir complexity and hydrocarbon movement along with pressure depletion always poses challenge for determining the perforation and completion strategy to optimize the production. Zubair Formation is broadly divided into three parts e.g. upper, middle and lower, the upper and lower units are of utmost importance for the current study. An integrated approach was adopted utilizing the high-resolution borehole image outputs; which has not only helped in identifying thin bedded reservoir zones but also facilitated the understanding of detail reservoir geology and sand dispersion.
Integrated formation evaluation and workover design is always the key to sustain the production and it becomes even more important when the reservoir is highly heterogeneous in nature and coupled with declining pressure trend. Therefore, an innovative methodology was necessary to address the uncertainties. High resolution borehole images were utilized to determine the sand count, which can detect even the thinnest reservoir layer in the formation. Heterogeneity analysis was also performed to understand the relative sorting of the different reservoir units; sorting has a direct relation with reservoir permeability and thus reservoir productivity. High resolution sedimentary analysis was performed to understand the detailed sedimentology using the borehole image derived dip data; cross bedding types were identified which provides fair idea about depositional energy condition along with depositional environment. All the high-resolution inputs were integrated with openhole logs and volumetric results, which led to a clear deterministic picture of the reservoir, based on which crucial decision was taken.
This integrated approach was adopted in three deviated well sections in Zubair formation, which has facilitated in improving the well performance. Detail sedimentary analysis and cross bedding typing in multiwell helps in fine tuning the sand dispersion in the reservoir model; which in turn found to be helpful for deciding future well locations.
One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.
The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.
Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.
Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential
Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study.
Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia.
Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery
This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model.
Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty.
Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability.
Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.