Historically, it has been a challenge to analyze and predict water cut or water production. While predicting water production may seem less relevant as compared to oil production, produced water poses many challenges. The difficulty rises when surface facilities cannot handle the water produced and reservoir pressure declines sharply as a result of excess water production. Multiphase flowmeters (MPFMs) have in the past few decades gradually replaced the conventional approach of metering multiphase flow streams using test separators. However, MPFMs have been faced with several challenges including flow assurance problems and high bottomhole temperatures and pressures. In addition, they have a threshold below which the accuracy of the measurement of water production will be highly questionable due to design and technology limitations. As a matter of economic decisions, it is necessary to detect and estimate early and post water breakthrough trends respectively. Several models to forecast water breakthrough have been developed. Among them is the famous water cut (WC) versus cumulative production (N p ) plot. This paper presents two empirical models to address the inability of MPFM to detect early water breakthrough below a threshold and to provide an alternative technique for modeling post water breakthrough. The models developed in this work predict water breakthrough using fluid volumes, bottomhole pressure and temperature. The first technique predicts early water breakthrough when the plotted function shows a deviation from a straight-line trend. In the second model, the water cut equation is modified for post water breakthrough prediction. Previous studies of water cut (WC) have focused on the production of water above the MPFMs threshold. The models derived in this paper provide accurate water cut estimates below MPMFs threshold and reliable post water breakthrough analysis.

Recompleting the wells with an artificial lift system requires a large capital investment in addition to rig intervention, a capital which was not made available due to worsening security condition in Libya in the period between 2014 − 2017, therefore, rig-less gas lift system via Coiled Tubing was chosen as the most efficient, reliable and cost-effective technique to revive oil production from 12 dead wells. The results of this pilot project were very satisfactory. The technique involves running coiled tubing inside the production tubing of a dead oil well, the coiled tubing is then hung over an additional special tubing hanger, made specifically for this project, fixed on the Xmas Tree. The gas is injected down continuously through a single point at the end of coiled tubing which is mixed with the oil in the production tubing annulus and helps lifting the liquid to the surface. Since compression system was not made available, due to cost cutting procedures implemented by MOG, the injection rate and injection pressure were supplied through a 2″ pipe connected to a gas well which had high wellhead pressure. Since the wells had been dead for a couple of years, there was a high uncertainty in the design due to the lack of fresh data, therefore, N2 lifting with downhole slickline gauges and surface testing were utilized to obtain reliable and fresh data for the final design. Since, the Coiled Tubing Gas Lift System CTGL technique was implemented in Libya for the first time, two wells among 12 dead wells only were selected for the Pilot project. The results of the two wells were satisfactory. Oil production from the first two wells increased significantly from 0 BOPD to 4500 BOPD, which increased the overall total field oil production by 100% from 4500 BOPD to 11,000 BOPD. Since the reservoir communication is extremely high, nearby wells’ production was positively impacted as well, and overall field production increased from 4500 BOPD to nearly 11000 BOPD in two months. The novelty of the technique comes from the utilization of the wellhead pressure of nearby gas wells as a source of injection pressure and injection rate which made reviving dead wells possible without investing in compression systems, seen as uneconomic for a pilot project.

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.

An Artificial Lift Optimization Tool has been developed in house by the Field Development team of South and East Kuwait Group of Kuwait Oil Company. The tool evaluates pump performance and identifies optimization opportunities quickly providing options to increase production and enhance pump life. Additionally, the tool identifies groups of wells with atypical conditions that will make them candidates for remedial actions such as well intervention work for pump upsize and increase well deliverability. The Artificial Lift Optimization tool is in the form of an Excel based workbook created with advance functions and macros using well-known oilfield equations for well performance analysis under various conditions. The tool is automated and compares measured information with design parameters through which it highlights two important pump operating conditions; 1) Wells with pumps performing out of the desired design parameters, and 2) Wells with opportunities to increase oil production based on well-reservoir potential. The first condition allows engineers to improve pump's runlife and associated costs, while the second provides options to maximize oil production. The AL Optimization Tool creates quick and easy to review well lists based on these two conditions for further analysis, reducing considerable time and efforts required otherwise for a similar exercise done conventionally. Additionally, a user-friendly interface allows the user review individually any selected well and identify in a glance pump performance and optimization opportunity. The tool is successfully being used since 2017 by the Field Development South and East Kuwait team for routine integrated well-by-well review and AL Optimization meetings with other stakeholder teams. Considerable incremental oil production has been added to the asset with quick gains identified from the AL Optimization Tool. The ESP pump life has been greatly benefited after troubleshooting many pumps to operate in the design operating range. The Artificial Lift Optimization Tool is a customized automated tool developed for managing the performance of Artificial Lifts wells installed in the Greater Burgan field of Kuwait. It gathers relevant production and reservoir related information from multiple data repositories to evaluate pump and well performance enabling quick optimization opportunities. Over 1000 wells operating with AL in Burgan field can be grouped quickly in different categories based on pump operating conditions for detailed analysis selectively by respective stakeholder. The tool has provided to FD team considerable ease in performing the AL optimization task efficiently and quickly. Development efforts for further automation and escalation to other areas of KOC are ongoing.

The change in global oil price has led Oil producing companies to chase each and every barrel of oil either through optimizing their production or through minimizing the production losses pertaining to various reasons. The Kuwait Oil Company (KOC) has a vision to increase its production to 4 MMBOPD by year 2030. To fulfill this vision KOC has designed a Digital Oil Field system which is unique in world in various aspects. This Digital Oil Field is designed to achieve two main objectives, first objective is to minimize the oil production losses associated with downtime and second objective is to optimize the oil production at network and field level. To achieve its first objective KOC designed various workflows to chase the losses and identify its root cause. Once the root cause is identified the issue are fixed in minimum possible time. The workflows designed to achieve this objective were all combined under one main workflow Smart Production Surveillance (SPS). The Smart Production Surveillance comprises of various sub-workflows taking care of various elements which affect or may affect the production. The idea behind the SPS design was to capture the main reasons for production losses, report them as quickly as possible resolve the issue in time and resume the production back to normal. Also as a proactive active approach where prediction of issue is done through alarms and warnings system. For this purpose smart alarms are designed based on experience in Oil Field. These alarms help analyze the issues at well level and pin points the major issues. The objective of the Digital Oil Field system is to improve the oil production by optimization. This objective was met by designing an extensive surface network model comprises of seven gathering centers for seven fields. To run this network model around twelve hundred well models were prepared which acts as an engine for optimization calculations.

Sabiriyah Mauddud and Upper Burgan are two of the giant reservoirs in North Kuwait(NK) under active water flood since 2000. About 400 MBWPD of water is currently being injected to maintain the reservoir pressure & improve the production/recovery. A comprehensive workflow process was developed and implemented to understand the waterflood performance, pressure-production response trends and map the opportunities to encash the benefits in terms of quick oil gains. The paper discusses the best practices adopted to increase production from two of the water flooded reservoirs in NK. Sound workflow process was created by integrating the technical inputs under collaborative environment from subsurface & surface teams. Series of segment reviews are conducted to understand the connectivity between producers & injectors, duly integrating all surveillance data. Analytical diagnostic tools have been used to distinguish between the good water and bad water and improve the VRR & sweep. Live ESP data is monitored and tracked at intelligent field collaboration centre to decide about the actions for the wells requiring ESP upsizing, downsizing and VSD/choke optimization. Wells with running ESPs were identified for VSD & choke optimization, using rationalized technical criteria. Wells with failed ESPs are reviewed for smart replacements with water shut off/water flood conformance & ESP re-design. Simultaneous actions for the well model creation; running sensitivity and scheduling in the workover rig are taken up. ESP upsize, along with VSD installation/choke optimization, was implemented in number of wells with significant oil gain (about 11% enhancement within a short time frame). As a part of the process established, this activity has become a regular practice in NK. Such wells are under constant monitoring so that water injection actions in nearby injectors, if needed, could be taken up such as allowable management, arresting the declining trend etc. The benefit of mega water flood activities have been reaped in terms of production enhancement adhering to the best reservoir management practices. Quick understanding of the Water flood response and relignment of actions on the associated wells via rigless and rig workovers is the key to the success for significant ramp of the NK production within a short time window of 6-7 months. Several work flow processes established during the campaign are now deeply imbeded within NK asset.

In 2012, the North Kuwait Field Development Group led a change in reservoir development strategy to increase oil production through a number of mechanisms, including a transition from vertical wells to horizontal wells to increase reservoir contact in alignment with reservoir management best practices. Over 340 horizontal and high angle wells were drilled and completed between 2012 and 2016, targeting four main reservoirs in North Kuwait. Adoption of operational and well design best practices and appropriate drilling and completion technologies improved the drilling efficiency and completion performance for horizontal wells, as average drilling times were reduced. The latter, in conjunction with improved water-flood management initiatives, helped increase oil production to recent production rate records above 750 MBOPD. Drilling data associated with horizontal wells drilled throughout the campaign was continuously reviewed. The Reservoir Competency Asymmetric Assessment® (RCAA®) 1 methodology was used to understand the key drivers to improve drilling performance. A multi-disciplined team identified the main opportunities with relation to horizontal well drilling and completions and geological operational practices, and technology gaps. The key performance drivers and changes required to improve horizontal well drilling and production performance were ranked based on rig time savings and oil production gains. The implementation of operational best practices, well placement techniques, engineering design changes, technology adoption, mentoring, and knowledge management, delivered significant improvement in drilling performance. Average well drilling times were reduced by over 40% within two years of the horizontal drilling campaign ( Figure 1 ). In Q4 2014, the rig fleet grew from eight rigs to 23 rigs, presenting a challenge to continue drilling improvements during this expansion. The rapid growth in rig fleet combined with drilling more challenging well targets drove average well drilling times up to 61 days per well. This upward trend was reversed by continually applying the RCAA® process and innovative drilling operations tracking technology across the bigger rig fleet. Average well drilling times were improved to 53 days per well at the end of 2016. Figure 1 North Kuwait Annual Project Cycle Drilling Performance and Rig Count for Horizontal Wells Drilling Efficiency Index ® (DEI ® ) is a drilling and completions performance metric used to benchmark and track operational efficiency of the existing rig fleet or well type. It is a KPI that reflects both reservoir management and drilling practices. At the end of 2016, the North Kuwait drilling rig fleet of 23 active rigs was operating at one of the highest DEI ® levels. The improvement in drilling and well placement efficiency increased the active well count and helped North Kuwait obtain record oil production. An estimated value of $4 billion associated to capex reduction and improved oil production was delivered to KOC. The forward five-year plan for North Kuwait requires over 100 wells be drilled annually. Initiatives to further reduce drilling days have been identified and presented to the organization.

The global oil industry is a major user of energy in extracting, transporting, and refining hydrocarbons. We have previously reported on the potential for the practical use of solar energy in these operations, including both extraction and transport ("upstream") and refining ("downstream"), considering both the use of solar electricity from photovoltaic (PV) generation and the use of solar thermal energy in the form of steam from concentrating solar collectors. This work is available in the journal Energy (118:884-892) (https://doi.org/10.1016/j.energy.2016.10.107). In this report we provide some further background on the solar technologies we considered for oil industry use, and update our previous assessments. The results show that potential solar thermal capacity ranges from 34 to 88 GW t in upstream operations, and from 42 to190 GW t in current downstream operations. Potential PV deployment ranges from 7 to 12 GW e in upstream operations and 17 to 95 GW e in current downstream operations. New developments are planned and underway in Kuwait; these new upstream and downstream projects collectively could use solar thermal capacity of 68 GW t and 3.2 GW e PV, and constitute a major fraction of the worldwide potential.

Produced Water is a major challenge in the oil and gas industry. Water production increases worldwide as more reservoirs depleted over time thus more resources needed to handle the unwanted produced water. Managing the subsurface water conformance maximizes hydrocarbon production and reduces operating cost that is mainly expected from the unwanted water production. It is important to identify the water source to solve any problem related to the unwanted excessive water production. Once the mechanism of the water production is understood, an effective strategy can be designed to detect and control the produced water. Different technologies and methods have been developed to control produced water. For example, Production Logging Tool (PLT) and Chan's WOR diagnostic plot are two common methods for determining the presence and causes of the unwanted excessive water production. In this study, Downhole Water Sink (DWS) completion technology is adapted to maximize reservoir recovery by reducing water cut with oil production, the excessive water is produced through a bottom completion and the oil is produced from the top completion. The design of a successful DWS requires detailed planning for the completion location and the production strategy. The aim of this study is to evaluate DWS technology performance in vertical oil wells located in Middle East Reservoir, which have severe water coning. In addition, economic analysis results were obtained by comparing the conventional wells with DWS wells to investigate the effect of DWS in reducing the operating cost. Results showed that the DWS completion minimized the water production by 18% and enhanced oil production by 26% compared to the conventional completions. In addition, several diagnostic tools applied to evaluate the water to enhance the proposed solution in which is applied to the candidate reservoir.

To improve Oil production rates and recovery factors North Kuwait shifted its exploitation strategy from vertical to horizontal completions. These horizontal ICD completions did indeed reduce the draw down pressure within the reservoir, thereby delaying water breakthrough. When water did eventually breakthrough, there was no completion mechanism to effectively control the conning effect, other than choking back/reducing the flow rate further with the consequent further loss of oil production. Additionally, water shut-off opportunities in passive ICD-completed wells were limited and marginally successful, since the water moves laterally along wellbore to adjacent compartments. The coning control completion (CCC) technology is an excellent emerging technology for improved oil recovery from water drive reservoir. The coning control completion (CCC) technology, applicable only in vertical or moderately-deviated wellbores (< 60°), is a technology that revolutionizes the development strategy of water drive reservoirs. The fundamental principle of this technology is to create a pressure drawdown, or pressure sink (ΔP), at or just below the OWC within the water leg, equal to or marginally more than the ΔP across the perforated interval within the oil leg. This drawdown retards the progression of water cone into the oil column and can be achieved using an inverted, bottom-discharge high-volume ESP. A preferential flow of the bottomor edgewater is created, parallel to the bedding plant, just under the OWC. The disposal options for the diverted water is either to "dump" into an under lying aquifer, or to preduce to surface for processing and re-injection, if necessary. For the interval perforated, the candidate well flowed naturally at rates six (6) times the calculated critical coning rate with a subsequent early water breakthrough resulting in a 45% loss in oil production. After commissioning the inverted ESP system water cuts have not only decreased by 50%, but also stabilized. After a planned or unplanned ESP shut down, the water cone redeveloped, but was brought under control again, and water cuts reduced and stabilized accordingly. Flowing BHP at the oil perforations, ESP intake pressure, and watercut are all monitored closely to ensure the watercut from the oil perforations are maintained at an optimum level, but not allowed to disappear. ESP rates are estimated by correlating the intake and discharge pressures from the specific pump curves. With inverted ESP's the coning control completion technology facilitates reduced surface water production while increasing oil production from partially-perforated oil columns at much higher than critical coning rates. A direct benefit is derived from subsurface disposal of the pressure-sink water to underlying aquifers within the same wellbore, significantly reducing surface water processing, handling, disposal and associated operational cost.

Oilfield development generally goes through multiple stages of development. Different stages have different development effects and features. Waterflooding characteristic curve is one of the main methods of development evaluation and oil recovery forecast in waterflooding oilfields. The chart of relationship between water content and recovery degree is directly applied to predict recovery factor. However, the production data could not be in accordance with the curve in the chart in the course of practical application. In order to improve the precision and applicability of water drive characteristic curve charts, based on seepage mechanics and material conservation principle, waterflooding characteristic formula between accumulative oil production and accumulative liquid production was deduced. Using mathematical equation method, a new relation between water-cut and recovery degree considering different time-phased actual development data was presented and the corresponding formula of water cut increasing rate was derived. Fitting parameters by regression fitting method from the actual production data was employed as the reference value for the revised mathematical model and the corresponding water drive curve cluster was drawn based on the fitting-curve. At the same time, the method of time-phased water drive effect evaluation was presented. Results showed that recovery factor of waterflooding reservoirs predicted by improved chart is more exact and the fitting degree of water cut between calculated and actual data is better than by existing charts, demonstrating that the improved chart has strong practicability in waterflooding development effect evaluation and index forecast. Those conclusions improve the waterflooding theory and provide useful guidance for effect evaluation of water displacing, water cut calculation and oil recovery ratio prediction for different stages. The presented research content furthers the theory of waterflooding, and builds theoretical foundation for the technologies of development evaluation in waterflooding reservoirs.

Some heavy oils reservoirs present an unusual behavior when put on production under significant drawdown conditions. In these reservoirs, the high formation depressurization increments the recovery factor and accelerates the production rates driven by a solution gas mechanism. Due to the chemical and physical properties of these oils they tend to stabilize the dispersion of gas bubbles, promoting the generation of foam in the oleic phase. This foamy oil when compared with conventional oils result in a more productive response at similar drawdown conditions. The foamy oil phase behavior is the result of a number of complex mechanisms and requires a good understanding on each of them to estimate the potential response of these reservoirs. In this work, the role of key factors that affect the bubbly oil production is summarized. To outline the significance of key variables on the performance, a commercial optimization and uncertainty analysis software coupled with a mechanistic simulator is used. The simulator allows a detailed modeling of the physics involved on the generation and behavior of the foamy oils, in which the foamy oil is modeled as a disperse phase of gas bubbles in the oleic phase, including small mobile gas bubbles and larger trapped gas bubbles flowing as discontinuous gas dispersion which affect foam viscosity, compressibility, mobility and relative permeability. Fluid properties used in this work are from Maini (1996) . The sensitivity and optimization analysis performed in this work on key reservoir variables and well operational parameters shows the significance of each factor on the production response. The relative importance of each variable is reported in tornado diagrams. Results showed that a strong approach on handling the reservoir unknowns are as crucial as the control of operational parameters from reservoir management point of view. Nowadays the foamy oil behavior and its favorable production response are not totally well understood. Solutions have been proposed but they are still controversial and the use of horizontal wells introduces more complexity in the production operations. In this work is provided an in-depth optimization and uncertainty analysis to outline the role of each major parameter affecting the production response and the recovery efficiency in this type of reservoirs using horizontal wells.

The GC-01 KwIDF system has been deployed in the East Kuwait area of Burgan oil field and includes real time production surveillance instrumentation for wells and production facility. The raw data from the wells and facility is integrated with well and network models in an automated workflow process for surveillance and analysis of the GC-01 production. The Burgan oil field integrated digital field (KwIDF) automation system utilizes wellhead pressure and water-cut measurements for automated calibration of well and surface network models. The KwIDF system workflow utilizes calibrated well models and real time data to identify changes in GC-01 daily production and reconciles it with the contributing wells. The workflow identifies wells with production changes and associates them with key well and facility parameters for instant diagnosis and analysis of daily production issues. This paper describes the application of real time data and integrated models in an automated workflow for quick identification and analysis of daily field production. Examples describe how the workflow has been used in quick analysis and decision making to optimize daily production and achieve sustainable targets in one of the production facilities of the Greater Burgan Field in Kuwait.

Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of oil in Bakken only. However, the predicted primary recovery is still low as 5-10%. Therefore, seeking for techniques to enhance oil recovery in these complex plays is inevitable. In this paper, two different approaches have been integrated to investigate the feasibility of three different miscible-gases which are CO 2 , lean gases, and rich gases. Firstly, numerical simulation methods of compositional models have been incorporated with Local Grid Refinement (LGR) of hydraulic fractures to mimic the performance of these miscible gases in shale-reservoirs conditions. Furthermore, implementation of a diffusion model in the LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) model has been conducted. Secondly, different molar-diffusivity rates for miscible gases have been simulated to find the diffusivity level in the field scale by matching the performance of some EOR pilot-tests which were conducted in Bakken formation of North Dakota, Montana, and South Saskatchewan. This study approved that diffusion flow is dominated in these types of reservoirs. Therefore, the injected CO 2 needs a significant molar-diffusivity into formation-oil, so it can penetrate into shale-matrix and enhance oil production. However, some of CO 2 Pilot-tests showed a good match with the simulated cases which have low molar-diffusivity between the injected CO 2 and the formation-oil. Accordingly, the rich and lean gases have shown a better performance to enhance oil Recovery in these tight formations. However, rich gases need long soaking periods and lean gases need large volumes to be injected for more successful results. Furthermore, number of huff-n-puff cycles has a little effect on the injected-gases performance; however, the soaking period has a significant effect. This research project demonstrated how to select the best type of miscible gases to be injected in unconventional reservoirs according to the field candidate conditions and operating parameters.

Artificial lift is widely used by Kuwait Oil Company (KOC) to both accelerate and increase oil production. The electrical submersible pump (ESP) is one of the most commonly used artificial lift systems in oil and water wells. The ESP is a multistage centrifugal pump placed down in the wellbore, capable of delivering high pressure increments for large oil rates. Reservoir oil is always saturated with natural gas, which will be separated from the oil as the pressure is decreased below the bubble point pressure. Since oil production is based on pressure drawdown, ESPs are likely to experience free gas in the suction fluid. Due to free gas present, several gas locking and ESP trips are observed. This technology is taken into consideration to minimize the free gas produced into the pump. Application of this technology can lead to more stable flow, less ESP trips and increased its run life of ESP. More over, suitable cooling mechanism has to be set up for the motor protection.

Carbonate reservoirs are known for complexity to oil recovery industry, one reason is the dual-porosity pore system. In macroporosity regions where pores are mostly effective for fluid flow and therefore viscous flow will play a role in oil extraction, while in microporosity regions contribution of pores to permeability is very limited and results in a large amount of residual oil entrapment. The purpose of this paper is to investigate the response characteristics of diffusion to porosity (include percent fraction and pore size ratio of macro- and microporosity) and permeability. Then with the help of permeability to evaluate the efficiency of CO 2 diffusion for oil extraction from different porosity composition core plugs. In order to achieve this objective, we use integrated carbonate core samples by pore structure characterization to study the feasibility of diffusion macro- and micropore regions. First, SEM and MICP experiments were introduced to characterize the bimodal pore systems, these results were combined with permeability measurement values as basic parameters for evaluation. Then the response characteristics of CO 2 diffusion to macro- and microporosity will be described by the performance of CO 2 injection for oil recovery with dual porosity carbonates. With the result the first observation was the dual effect of macroporosity that it lowers the resistance for fluid flow and meanwhile reduces the exposure duration for CO 2 to diffuse into the microporsoity regions. Furthermore, percent fraction, tortuosity and ratio of pore size between macro- and microporosity are critical parameters for CO 2 diffusion. Also with different dual porosity component core plugs, various ultimate oil recoveries were acquired and all recovery curves were divided into two different parts that contributed by viscous flow and diffusion respectively. Through comparison the different diffusion performance in various dual porosity core plugs, response characteristics of CO 2 diffusion to macro- and microporosity were finally concluded. Acquire the knowledge of CO 2 diffusion response characteristics to macro- and microporosity makes oil extraction from microporosity regions which have limited contribution to permeability possible. It shows an optimistic prospect of oil recovery by diffusion mechanism which ever been neglected and provides one more option for EOR method design in low permeable reservoirs. In addition, suggestion will be presented to extract oil effectively using CO 2 injection in case of high percent fraction of microporosity reservoirs.

Within the framework of reservoir management streamline simulation finds one of its typical applications as one of the effective tool to improve gasflood and pressure maintance performance. Streamlines provide an instantaneous visualization of flow patterns as a function of reservoir heterogeneity. Additionally they also provide an estimation of the well allocation factors (WAFs) between injection and producing wells. Such information is a default outcome from streamline models but not from finite difference simulation and it is particularly useful in optimizing and balancing well patterns and field scale injection rates. However finite difference simulation has the advantage of implicitly taking into account all the details of an existing simulation model, especially advanced well management strategy. In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of two key parameters: injector efficiency (IE) metric and WAFs. The optimization approach consists of a three step procedure starting with streamline analysis using commercial software which combines the power of finite difference simulators and streamline technology to derive streamlines from the flux field generated by the finite difference simulation that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second using a simple analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an onshore tight sandstone reservoir where the pattern balancing has led to incremental production of 3.5 % over the 5 year forecast in which the IE average of the field is the benchmark for whether more or less injection volumes were required while obeying facility constraints.

Kuwait has abundant proven reserves of oil and recent discoveries suggest that Kuwait has significant heavy oil reserves as well. Heavy Oil in Kuwait ranges from conventional (easy to produce) 16 °API in lower Fars and unconventional (difficult to produce) tight oil and Tar-Mats. Developing these reserves in an environmentally compliant and sustainable manner is a national priority. The challenge of increasing national production to 4 million barrels per day will depend in large part on our ability to develop and adapt the technologies necessary to be able to exploit these heavy oil reserves. There are around 160 types of crude oils being produced worldwide and the price differentials between crude oils can be $15 /barrel or higher. Refiners find themselves faced with the difficult question of searching for crude blends to maximize the use of their existing assets or to choose crude blends, which will require additional capital investment but will offer opportunity to increase return on investment. As per World Oil Outlook by OPEC, a continuation of moderate light-heavy crude differentials in the medium-term is indicated, followed by a progressive widening in the long-term. The moderate differentials in the short-term stem from the existence of excess refining capacity and the lightening of the global crude slate. The long-term trend toward a widening of the differentials, with heavy sour grades especially affected, is mainly due to a return over time toward a more balanced downstream as well as a gradual shift toward a more heavy crude slate. This will be alongside continued declines in inland and especially marine residual fuels demand. In addition, the on-going trend toward sulfur reduction in transport fuels will further differentiate crude oils depending on their sulfur content. In General, an Increase in Light-Heavy differential on both crude side and product side indicates better Refining Margins leading to improved profitability. Historically, the petroleum industry supply chain has been divided into three discrete sectors: production, transportation and refining. Typically, crude is produced and made ready for transportation by production operations, and it is transported via pipeline or ship, train or truck to more sophisticated and complex refineries. Once at the refiner, the crude oil is refined into transportation fuels and other high-value finished products. The downstream sector of the hydrocarbon industry continues to optimize processing schemes to take advantage of the lowest-cost crude oil, of which a significant portion of the "opportunity crudes" are heavy oils. Maximizing domestic processing of Heavy/Sour crudes is a KPC 2030 Strategic Direction for KNPC. Accordingly, Al-Zour Refinery (ZOR) is planned to handle heavy crudes. However, Processing of Heavy Crude in an Oil Refinery is an opportunity as well as Challenge. In my presentation, I will highlight the same from a refining business prospective.

Dumpflooding from a strong Aquifer to support pressure to another depletion-drive reservoir is not new to the oil industry, neither to the region. In cases where the natural Aquifer pressure is insufficient to deliver adequate volumes to meet pressure support requirements, or the Injjectivity of the target reservoir is relatively low, artificial lift is required. This was the case in the North Kuwait Asset where Injectivity was poor owing to the relatively low natural fracture density of the Carbonate reservoir being flooded. Since the conventional encapsulated (POD) systems required one (1) seal-bore packer, one (1) encapsulated ESP system, and one (1) ESP-packer, it was decided to test an alternate and simpler system that required only two (2) ESP packers that would achieve the same result of the POD system. Deployment of this new tandem-ESP-packer system proved less complex and required less rig time than the encapsulated ESP system. Both packers were set simultaneously in one operation with the ESP function test to surface-pit giving excellent results. After opening the SSD's, the ESP operating parameters, measured at surface, indicated optimum pump performance at expected injection rates. The Tandem-ESP-Packer Dumpflood completion system provides fewer sealing interfaces than the conventional encapsulated ESP system, and therefore fewer opportunities for leaks. Additionally, it affords a very simple one-trip system for less complex deployment, and retrieval, when necessary. This alternate system also provides easily-deployed, immediate pressure support in areas of the reservoir/field while awaiting the installation and commissioning of major surface Injection facilities.

Marrat reservoir in Magwa field in Greater Burgan, Kuwait is a carbonate heterogeneous reservoir belonging to Lower Jurassic. Marrat is classified as a tight reservoir with an average permeability of 17md and contains light oil of 38deg API. The formation is around 2400ft thick divided in three sub layers namely Upper, Middle and Lower Marrat. Middle Marrat is the main oil reservoir which has been perforated and tested to be oil producing in almost all the 30 drilled wells. The reservoir consists of Grainstones, Packstones, Wackstones and Mudstones. Marrat was put on production in 1984 and solution gas drive is the main drive mechanism. The reservoir is naturally depleted due to limited water aquifer. The reservoir pressure declined 17% from the initial reservoir pressure within 15 years to current pressure of around 8000 PSI. Field Development Plan envisages pattern and peripheral water injection and facilities development for water injection is planned. Asphaltene flocculation at wellbore, tubular and surface facilities has been recognized as a severe problem. One of the options to avoid asphaltene problems in the reservoir, including the near wellbore region, is to maintain reservoir pressure and flowing BHPs above the asphaltene onset pressure (AOP) of ~ 6500 PSI. Formation fluid contains around 1000 ppm of H2S and 4% CO2 which throws a corrosive environment also to tackle with. The well head equipment with present metallurgy often leaks on pressure tests and there is a plan to replace during future work over jobs. Coil Tubing Cleaning of tubular with light aromatics is a routine operation to maintain production from wells. Increased demand of oil necessitated safely increasing oil production from Marrat reservoir. Keeping in view the challenges, a multi-disciplinary team was formulated to look into all possibilities. Focus was on Acid Fracturing Technique which had proved to be successful in the past. However with advancement in acidizing and diversion chemicals, the new system was field trialed. This paper will discuss the process to select the wells and successful attempt of acid fracturing in two wells to tap oil from new areas.