With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development. The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles. The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.

Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Minagish Oolite (MO) reservoir is the main oil producer contributing more than 95% of the current production in the UG field. The field water cut has been increasing and currently is around 60%. The increasing water cut in the UG-MO reservoir is posing a major challenge in maintaining the oil production rate as the higher mobility of water compared to the oil will lead to a decline in the oil production rate and prevent oil producing zones from contributing effectively. The increase in water cut is attributed to the rise of the OWC and the natural water aquifer that underlays the oil column and extended across the reservoir. UG-MO reservoir consists of different carbonate layers all are hydraulically connected with high vertical to horizontal permeability ratio (kv/kh) that ranges from 0.8 to 1.0. The high kv/kh ratio leads to water coning phenomena especially in the high pearmability zones. The petrophysical properties of the UG-MO reserviur shows lateral variation in permeability in each layer. The fluid PVT properties are consistent arcoss across the field with slight change vertically, the oil viscisity ranges from 2-8 cp and H 2 S and CO 2 levels are 1.5% and 4%, respectively. In order to address the increasing water production in UG-MO wells, the Field Development (FD)-UG team decided to implement Inflow Control Device (ICD) completions in deviated cased hole wells, open hole high angle deviated wells and horizontal wells. In addition, the work extended to install ICD completion in existing horizontal wells. The current total number of ICD wells in the UG-MO reservoir thirty-four To maximize the success of the ICD installation campaign, the FD team along with the completion equipment provider have undertaken key steps in developing a robust design criteria and workflow upon the completion of the assessment phase. The assessment phase included a reservoir simulation study conducted by the asset with a third-party consultancy firm to determine the increased incremental oil and the decrease in water production from ICD completion implementation across the field, in addition to a metallurgy study to identify the suitable material for ICD completion to be used in the UG-MO reservoir. The workflow included identification of the design objective for each type of well and consideration of the reservoir fluid properties and reservoir rock characteristics. The compartmentalization is based on the permeability that is estimated from recorded logs in addition to boundary mapper technology in some existing wells and the nozzles size selection is based on sensitivity runs on well-centric simulation models. The performance of the ICD completions in UG-MO is showing good results and success in the new drilled open hole horizontal wells and high angle open hole deviated wells while the results of the cased hole wells showed limited success due to associated well integrity issues (e.g. poor cement jobs and ineffective remedial jobs) and the complexity of the completion with the presence of Electrical Submersible Pumps (ESP). Moreover, the performance of ICD as re-entry in existing horizontal wells showed moderate results. The application of ICD will add value when the objective is clear, and the design criteria/ workflow is well defined and modified with time based upon the results and the performance evaluation.

The unconventional Bahrah project aims to exploit the deep mid-cretaceous tight carbonate formation, which is prolifically hydrocarbon saturated, but with unsustainable productivity. Because of a challenging reservoir and large variations in heterogeneity, openhole horizontal wells with unique completion techniques were deployed with multistage acid fracturing within their lateral sections, with minimum rig time and a high degree of accuracy. From an operational standpoint, exploiting these limestone layers with this method means that more fracture initiation points can be achieved across the heterogeneous lateral and the size of the treatments is ideal for multiple applications in a shorter period, helping boost and sustain production. Due to the unconventional reservoir nature of this field, optimizing fracturing stages and perforation cluster placement distribution becomes key to the approach. A holistic acid-based fracturing service was introduced that integrated two components—a completion suite with fit-for-purpose swellable packers to segment the annulus coupled with sliding sleeve devices in the liner that deploy ball-drop isolation and perform each fracturing treatment to a newly exposed zone. The technology is based on distribution of intelligent packers along the lateral section to develop the fracturing stages. Intelligent packers and their ports are placed based on the formation's petrophysical and mechanical properties to increase the cumulative production in a shorter timeframe. Acid fracturing using an enhanced diverter-based technique is then employed for improved individual stage targeting. By combining these two processes into one continuous operation, the use of wireline for perforating and plug setting is eliminated, making the new multistage technology economical for these unconventional wells. Additionally, with coiled tubing-conveyed shift tools, the sleeve devices can be operated later in one run for any re-stimulation opportunity. The operator is forced to address the unique challenges of well operations, formation technical difficulties, high-stakes economics, and untapped potential from these layers. This has required an advanced and holistic fracturing technology, first of its kind in this field, to be applied. The completion and stimulation systems not only saved significant rig time to complete the well with long multilayer intervals, but also significantly helped reduce expenditures by standardizing design, simplifying the key operational stimulation complexity, enhancing system reliability. This well and completion design allowed for fracturing efficiency improving overall quality, health, safety, and environment performance for this project. To date, more than 300 treatment stages have been successfully pumped. As more treatments are executed and experience is gained, stimulation design is optimized and productivity target identification is improved, providing further value to the operator. Finally, the lessons learned from a project-management viewpoint are also examined, discussing streamlining operations and addressing stimulation development. The technical and operational learnings during this project can serve as a best practice in other fields where similar challenges are encountered.

Traditionally most Reservoir Engineers give emphasis in matching Water-Cut, GOR, SBHP/FBHP and Cumulative Oil/Water & Gas production. Matching the above said will yield good results at the well level, however what is happening within the layers where the well is completed still remains unclear. In addition to the conventional production data matching various well surveillance data like Pressure from the RFT data will enhance tracking of the Vertical/Aerial distribution of reservoir fluids. Matching PLT data will result in improving the relative contribution of different layers in the dynamic model. Capturing time-lapse changes of Water/Gas saturation as observed from the TDT/PNC logs in the model will mimic fluid flow and saturation changes in the dynamic model closer to reality. Identifying the amount of water unwantedly being injected in to the reservoir due to casing integrity and simulating its effect during history matching will help in capturing its impact on increasing water saturation and pressure near the well bore. At the same time due to the complexity and the resultant convergence which arise in modeling advanced completions, typically a positive to skin at the well level is considered to achieve the additional pressure drop which is observed in the constriction (Nozzle) of the ICD. However the effect of flow equalization as a result of implementing ICD is missed in the above approach. We propose a simplified approach by amalgamating the ICD's into an equivalent acting one. Using Amalgamation it is possible to compute the equivalent length and cross sectional area of an ICD that represents multiple ones. This reduces the number of ICDs in the model, avoids looped flow paths and correctly models annular flow along with great reduction in computational time and convergence. After thoroughly matching the dynamic model with observed data, well-surveillance data and capturing the flow equalization impact of advanced completions during the long history of 57 years the level of confidence in the history match has increased significantly. The history matched dynamic model is then used to generate Stream Lines to establish well pair interactions and identify the movement of injected water to optimize injection/production targets. Precisely capturing movement of OWC and tracking the size of Gas-Cap with time has significantly improved the confidence in planning wells. Wells locations thus released on the basis of model results show a good replication of forecasted saturation's and are so far doing well.

Since the start of the North Kuwait Jurassic Gas (NKJG) Project, Enhanced Technical Service Agreement (ETSA) in 2010 with Shell, Technology implementation has been a priority. The key challenge, following the successes of technology deployment at pilot level, is to deliver sustainable solutions, with business impact on the NKJG project, vis-à-vis production maximization, well cost reduction and ultimate recovery maximization. Moreover, NKJG technology focus, in line with business priorities, has recently changed to assurance of near- and medium-term gas supply. An integrated technology mapping workshop, led by Shell Technology Deployment experts from the Netherlands, was held during 18-20 th January 2016, using a refined technology mapping and prioritisation process applied in Shell assets globally, to ensure that KOC technology efforts are prioritised and aligned across the organisation at large and deliver maximum value to NKJG in particular. The workshop participants were drawn from six discipline teams (Drilling and Completions, Production Operations, Well Intervention and Management, Subsurface, Project Management and HSE). From the technology mapping workshop, Downhole fibre optics; Well Reservoir Facility Management (WRFM); Managed Pressure Drilling (MPD); Underbalanced drilling and Annular Isolation technology emerged as the top five technologies to deliver the most value to NKJG project, considering the participants focus on the business challenges, related to well quality improvement, reservoir performance understanding and optimisation of field development. Furthermore, the workshop also identified ‘solution gaps’ in addressing many of the subsurface related challenges (Optimise integrated field development, improving predictability of reservoir performance) and additional technology solutions will be required to address these gaps. The value of technology ‘at risk’ of not realising full value from implementation is assessed to range from 30 to 70% of the full value of the technology. These are due to both technical and non-technical risks in implementation. Key non-technical risks identified such as organisational misalignment, contracting delays need to be addressed in order to realise full value from technology implementation. The workshop participants proposed the following improvements to support technology implementation; Robust, detailed and realistic multiple year implementation plans taking account of standard KOC contracting and procurement processes. Annual work plans driven by technology implementation priorities rather than the opposite. Progress of the top-ranking technologies tracked at senior management level. Preferably monthly or quarterly as part of a decision review board (DRB) governance structure. Individual technology implementation targets to be included as shared KPIs of concerned Shell / KOC managers and Team Leads. This paper documents the outcome of the workshop in terms of the ranking of the business challenges/opportunities within NKJG, the ranking of technologies that need to be implemented to address these challenges, the technology mapping and prioritisation process followed, the key technology implementation challenges identified and their suggested mitigations.

Water conformance is a common challenge in oilfield industry especially in water flood and active water drive reservoirs where water production has a significant impact on production economics, oil recovery and facilities constraints. Water shut-off (WSO) is an essential solution to delay or minimize water production however effectiveness depends on treatment efficiency. This abstract will demonstrate extensive mechanical and chemical WSO experience in horizontal drilled wells completed with passive Inflow Control Devices (ICD) completions, with case histories from North Kuwait giant water aquifer reservoir. The main challenge during water conformance treatment is the proper diagnosis and the full understanding of the water flow profile; accurately identify the water source as well as reservoir understanding will help selecting the efficient WSO mechanism, which is crucial for a sound decision making considering the associated cost and the operational complications. Understanding reservoir geology, Integration of inflow profiling via Horizontal PLT and new technologies of water saturation logsare key to accurately identify the water source (heal, middle or toe side) and by turn WSO mechanism. This is done in integration of multidisciplinary domains of G&G, production and reservoir engineers and operation teams. Mechanical WSO using inflatable packers’ technologies were applied for isolating the toe side, while chemical WSO technologies used for heal side isolation in the open-hole passive ICD completions. Rig-less shifting of ICD sleeves used where active SSD-ICD's completion installed. The statistics of executed WSO results of many case histories have shown relatively good success ratio represented in reducing water cut from 80 – 90% down to 20 – 70%, increase oil production rate from 200 bopd up to 3000 bopd in some wells depending on water source. Furthermore, WSO enabled bringing some inactive high-water wells back to production. This helps extending well-life and by turn maximizes ultimate hydrocarbon recovery. Also, reducing the total water production to facility allowed increasing production of some other wells producing to same facilities. As key learnt lesson; managing the produced liquid rate and drawdown post WSO is essential to maximize the benefit of WSO and delay sharp increase of water cut. WSO solutions are in constant improvement. Integrating reservoir characterization, fluid inflow profiling and proper selection of WSO technique is crucial for any successful WSO decision. WSO became a common practice to maximize the oil recovery factor from Lower Burgan reservoir of North Kuwait fields.

At early stages of front end loading (FEL) of steam-based thermal recovery projects, oil companies make critical strategic decisions with limited understanding on how reservoir complexity, uncertainty and risk could affect recovery and economic performance. A solution is to measure front end loading (FEL) and improving it to meet a minimum level of project definition for sound strategic decisions. This paper presents a method to measure FEL by combining complexity and definition rating indices that account for a) reservoir structural, stratigraphic, rock, fluid, energy, static and dynamic complexity and b) definition rating indices and completeness of wells and surface infrastructure. Causal maps guide the assessment of complexity, uncertainty and risk in CAPEX, OPEX and cycle time of typical projects. Sixty-eight factors in eight matrices provide complexity indices and twelve additional factors account for completeness and definition indices for wells and reservoir under static and dynamic conditions. Five hypothetical examples using actual field data from analogs, illustrate how the method works. A causal map describes cause and effect relationships of uncertainty and risk for typical ranges of CAPEX, OPEX and project cycle times which translate into probability of success (POS). Finally, general strategies provide guidelines to reduce uncertainties and mitigate risks. By measuring and improving FEL companies increase the probability of success by mitigating risks such as higher operational expenditures (OPEX) to meet demand of energy, higher capital expenditures (CAPEX) for oversized processing facilities, and deferred production due to failures caused by extreme operating conditions imposed by high temperature, high pressure and corrosive contaminants. This method confirms the benefits of measuring the level of definition of a project, which is a best practice used in aerospace, nuclear, chemical, and other complex industries. It also improves the level of inter-disciplinary communication typical of reservoir-well-surface systems in steam-based EOR projects.

Leak in well bore tubulars & packers leads to communication between tubing/casing or Short/Long strings thus causing enormous production losses in Oil & Gas industry. Moreover, it can cause cross flow between different reservoirs. Sometimes leak may lead to charging of shallow formations thus posing a big threat to well integrity. The detection of the source of communication presents a big challenge to the industry. Knowing the precise location of a leak helps in designing an effective remedial action thus reducing downtime and repair costs. When a fluid leaks, it moves from the high-pressure side through the leak point to the low-pressure side, where it expands rapidly and produces a turbulent flow creating noise and temperature changes. Conventional noise and temperature tools are not capable of detecting the leak point with high confidence. However, the new generation Noise and Temperature logging tools have been able to locate such leaks precisely. This paper presents successful use of Spectral Noise Logging in combination with High Precision Temperature logging (HPT-SNL) in a dual-completion oil well in Kuwait Oil Company for identifying communication between the long and the short tubing strings. The acoustic tool contains a new-generation, high-sensitivity hydrophone – a piezo crystal element that records noise in a wide frequency range (0.1 – 60 kHz). Temperature tool utilizes a super-sensitive platinum sensor with a response time of less than one second. Leak was detected at the bottom blast joint of the long string that was causing water entry into the short string thus killing the well. The technology can be used in critical oil and gas wells to identify tubing and casing leaks and address well integrity issues. It can also be used in water injection wells to identify the zones of water intake.

Drilling in thin reservoirs is challenging task. But with easy pockets gone the reservoirs left are less than 5 to 10 feet and it becomes difficult to steer well exclusively in the sweet spot or sand in thin payzone. It is this reservoir which offer task to drill horizontal well and produce maximum where otherwise it would be difficult to produce even 200-300bopd from this thin layer of silty shales. Moreover the thin beds are like appearing or vanishing as we drill ahead due to facies change. This needs complete attention till the well reaches Target Depth (TD). Even a small fault of sub-seismic nature of 2 feet throw can offset the well from the sweet zone. But with advanced logging tools used in two wells helps to understand the nature of lithology and its productivity. Best application of this tools are in silty shales in Burgan Sands Upper (BGSU) which generally show high GR and often this leads to misjudgment of well not being in sweet spot. Logging While Drilling (LWD) logs and inversion was used whether the well is in productive zone or not. The LWD tools now have Azimuthal GR, density and resistivity. This gives a holistic picture of the lithology in the roof side or the bottom side of the lateral section. The wells under discussion were drilled with such advanced version of distance to boundary tool. After well was steered till TD, the data was processed by Petro-physicist to indicate possible payzone to decide completion. But due to high GR which is often prevalent in Burgan Sand Upper (BGSU) the entire well bore was not getting classified as potential payzone. But after looking the inversion and all LWD data sets it was conveyed that the Inflow Control Device (ICD) can be lowered for entire well bore length. As an outcome advanced ICD was lowered also against high GR zones which otherwise were not getting classified as potential payzone, and well were completed. The well was put on production starting with 1300 BOPD on 32″ choke and still after 18 months continues to produce. PLT results show that the zones indicating high GR and with poor log properties were also contributing oil. The paper discusses these wells and utilization of complete data set acquired at time of drilling and taking completion decision accordingly. The output of data of LWD has been fully utilized to complete the well successfully and given the confidence of doing so in other wells. In fact this experience was used in another similar looking well with unfavorable parameters and successfully completed.

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.

The HPHT, sour, deep, fractured and not so fractured carbonate Jurassic formations within the North Kuwait cluster of fields present extraordinary challenges in driving towards an optimized field development that maximizes liquid recovery and meet the gas production aspirations for the state of Kuwait. The Middle Marrat reservoir has been developed to date with cased and perforated liner completions across the 500- 700ft pay. However due to the high permeability contrast between the different reservoir flow units, the low permeability zones are typically not contributing. This is further exasperated with the inability to effectively acid stimulate large proportion of the net pay with a single stage bullhead treatment especially when the contrast in permeability between the various flow units is higher than one order of magnitude. Key to successful reservoir management of the Middle Marrat whilst maximizing well capacity to meet the production aspirations is to implement a completion and stimulation strategy that maximizes flow contribution from as much of the net pay as possible. Single stage bullhead matrix acid stimulation treatments like those executed in the past will only stimulate the top decade of permeability. The current 4-1/2" cemented completion ‘plug and perf’ standard will require intensive well intervention to set and drill out plugs in order to selectively stimulate individual zones. To develop an alternative completion and stimulation strategy for developing Middle Marrat, the first 4-1/2" multistage ball activated sleeve completion system has been deployed successfully in a Middle Marrat deviated development well. 2 out of 3 stages installed have been acid stimulated and flow tested showing excellent results. The operational experience and learnings acquired from the project have provided the necessary confidence to the organization to deploy the technology in tight gas and unconventional reservoirs within North Kuwait, but also challenge the existing cemented ‘plug & perf’ completion and stimulation approach for the development of the more conventional Middle Marrat reservoirs.

The initial development of inflow tracers was initially designed to provide qualitative information about identifying the location of water breakthrough in production wells. The proof of concept and application for water detection, initiated the development of oil tracers for oil inflow monitoring. Different approaches to install them permanently within a completion component were used, to provide risk free, reliable production monitoring without the need for intervention. Installing unique chemical tracers that are embedded in polymer materials in sand screens or pup joints, along select locations in the lower completion was to correlate where the oil and water is flowing along the production interval and how much. Innovation in the chemistry and materials designed to release to a target fluid (oil or water), enabled non electric wireless monitoring capabilities for many years of longevity in harsh well conditions, such as high temperature and highly acidic stimulation fluids. The evolution of inflow tracer signal interpretation, qualitative and quantitative interpretation workflows using models have also provided valuable insight to inflow characterisation. The latter can provide zonal rate information like wireline conveyed production logging tools, by inducing transients through shut in's or rate changes to create tracer signals that are transported by flow to surface and captured in sample bottles for laboratory analysis. A model based approach to match the measured signals with proprietary models through history matching workflow has also been developed. There are hundreds of well installations utilising inflow tracing monitoring technology today, where the majority have been in open hole completions in both sandstone and naturally fractured carbonate reservoirs on land, offshore environments in both platform and deep water sub-sea environments producing through long tie backs to FPSO's. The monitoring sensors are adaptable to most completion types in conventional and unconventional reservoirs. In most cases, inflow tracers can monitor clean-up efficiency, any subsequent restart and steady state production. Practical case studies will discuss the development of robust and reliable inflow tracer and technology and how operators have applied it over the past decade in a chronological order.

Openhole (OH) multistage (MS) technologies can maximize reservoir contact and productivity by optimizing the distribution of acid across the formation matrix. Successful completion of these reservoirs can be challenging. This paper discusses the recommended practice for optimizing OH fracture stages and cluster placement distribution within heterogeneous unconventional oil carbonate reservoirs based on formation, completion properties, and reservoir fluid distribution. Completion technology is based on distributing intelligent packers along the lateral section to develop the MS fracturing stages. Intelligent packer displacement influences fracture effectiveness and conductivity. Typical packer placement can undermine formation potential and productivity results. Packers and their ports are placed based on the formation's petrophysical and mechanical properties to increase the cumulative production in a shorter timeframe and help improve recovery. The workflow followed was based on analysis of the reservoir properties (porosity and permeability). These were later integrated with the measured rock mechanical properties. The developed integrated model was used to divide the rock into segments that share similar properties. The use of an advanced azimuthal sonic with a high signal-to-noise ratio and wider frequency response helped improve the accuracy in assessing formation mechanical properties. Additionally, conventional logs, when combined with formation mobility measurements, help calibrate the permeability model and classify the formation into distinctive clusters. These clusters are then grouped according to their mechanical and brittleness properties to form a separate unit with a selected fracture port to help ensure the necessary fracture length. The developed method provides an opportunity to determine the necessary fracture stages and reduce the risks of over or underplacement. It also improves stage integrity, helps ensure better distribution of the acid across the formation matrix, and provides effective propagation of the fracture network. The applied procedure follows an innovative workflow to optimize the fracture stage and cluster placement distribution across the reservoir using a new combination of advanced and conventional data acquisition and interpretation. The discussed case study demonstrates the benefits of engineered fracturing stage placement compared to a geometric displacement.

Acid stimulation is the means of improving the well productivity in hydrocarbon production wells. Carbonate formations are tolerance to wrong acid stimulation practices, and Kuwait reservoirs are not exception. Matrix stimulation for carbonate reservoirs is one of the most frequent operation in KOC. It is always associated with operational and technical challenges in order to select and design the proper stimulation method. The main challenges are selecting the acid type, concentration, dosage and diversion method, besides selecting the most suitable stimulation technique for each individual well and formation. It was important to create an adequate procedure to unify a solution for the faced challenges. Programming a software that provide a full acid stimulation program has been done by KOC Well Surveillance Group "First of its kind in KOC". The software is built based on KOC data base for all carbonate wells. These data went through a sequence of analysis and been grouped based on; reservoir's rock properties, fluid properties, reservoir's pressure/temperature, fluid compatibility, and formation lithology. By using the Software, the user will be able to overcome the mentioned challenges. In addition, the software is able to define the corresponding treatment radius (rs), diverter type (chemical or mechanical diversion, polymer or non-polymer based fluid), pre and post flush dosage and type, and prediction of liquid gain after the well stimulation. As a result, the variation in stimulation designs based on different level of experience and knowledge will be eliminated. Thus, the chemical dosage will be optimized from technical and operational prospective, which will reflect on the job expenses. The software is divided to five windows: two Coiled Tubing windows and two Bullheading windows (Mechanical Diversion and Chemical Diversion), and Matrix Volume Calculator window; which helps to calculate the required treatment dosage in order to cover the desired treated radius, given the casing OD and reservoir porosity.

In mature carbonate reservoirs, the potential for bypassed or under-stimulated pays need to be addressed in order to enhance the productivity of the wells. Reservoir restimulation is one of the viable option to do this. However, due to issues with completion, perforation and other associated issues that given wells may have, restimulation should be designed and implemented such that well productivity is enhanced while simultaneously maintaining the requirements for well completion integrity. Proper design for restimulation in thick carbonate reservoirs could eliminate any negative issues that may occur during completion and prevent integrity failure during the process. In thick carbonate reservoirs, like those found in the Middle East, the aforementioned criteria contain both petrophysical properties and current production profile obtained by production logging, establishing good foundation for implementing restimulation. Petrophysical properties help define the stimulation strategy necessary based on log potential, while the current production profile identifies the best location to stimulate over the existing completed perforated interval. In thick carbonate stimulation, uneven reservoir recovery is often observed and considerable parameters must be set during the stimulation design. Major changes to consider during the candidate evaluation for the restimulation in thick carbonate reservoir are: non-uniform pressure depletion across the formation, various pressure drawdowns, and change in PVT properties. In addition, wormholes which formed during the initial reservoir stimulation are major factor for consideration. These wormholes may act as thief zones during restimulation work and could lead to improper zonal coverage. This paper describes restimulation design strategy which has been tailored for well preparation based on mature well conditions while also considering factors of completion and well-integrity issues. The well preparation includes focus on the reperforation selection, post-reperforation production log evaluation and production profile matching. Within the stimulation strategy, fluid selection and placement strategy will be discussed, taking into considering all aspects of a mature well.

The purpose of this study is to carry out a participant Return on Investment (ROI) on one of ADCO's (Abu Dhabi Company for Onshore Oil Operations) Talent & Capability Management Division's (T&CMD) most important in-house programme – Leading People Performance (LPP). This programme is delivered by instructors from T&CMD. It is run over 2 modules of four days each. The LPP is designed to enhance the skills of managers by focusing on their ability to create and develop high performing teams and enabling these teams to function at optimal capacity . The programme is targeted at people who predominantly engage in people management responsibilities. Typically the participants will have between 5 to 10 years of relevant work experience and less than 5 years of relevant management experience. Participants are at grade 15 – 17 in a management / team leadership role. An overview of the programme can be found in appendix 1 . This study will not only carry out an ROI from Level 1 (reaction) to Level 4 (impact), but will also introduce a Level 5 component (Transfer Climate), which identifies the environmental factors that help or hinder a learner from applying their new knowledge and skills when back on the job. For the purpose of this study the population comprised of LPP attendees from the last three delivery cohorts i.e. 12, 13 and 14. These programmes ran during 2013 and the first half of 2014. The total number of attendees (participants) was 47.

Sustainable development of a mature field depends on various factors, which can be categorized into well level and reservoir level. This paper is a summary of experience of various techniques used at well level and reservoir level. The objective is to sustain/increase the level of oil production and reduce watercut using various completion methods & pressure maintenance. This Paper will elucidate a Field Development Plan for a mature field. Several possible options were tested like 1. Possible workovers 2. Combination of Horizontal and Vertical wells based on firm and dependent locations 3. Infill short lateral wells 4. Optimal production rate to minimse pressure decline by limiting the gas production and hence putting a check on GOR 5. Water injection strategy 6. Intelligent Oil Field Completion using ICD (Inflow Control Device). For the purpose of testing the best possible course of action; the reservoir was modeled and history matching was done with satisfactory results. Prediction Strategy was then deployed at simulation stage. The financial analysis for all the prediction scenarios were also carried out using Net Present Value (NPV) method to check the feasibility as well as profitability of the various envisaged Production Strategies. Based on the analysis, the maximum recovery was obtained from a combination of infill wells and ICD completion, but on monetary grounds, the best case consists of workovers and horizontal wells to tap the oil from segregated pockets. In the end, a comprehensive and extensive comparison of all the possible way-through options are discussed with pros and cons of each one. A sensitivity analysis was performed on economic parameters (e.g. crude oil price, operating cost, Taxes, Royalty, capital expenditures) to analyze impact on various economic indicators. This Paper presents novel ideas into the ever expanding sphere of Field Development. It presents an extensive review of the various aspects of mature field development and their economic analysis. The field in discussion is Makum-North Hapjan which contributes around 40% of total production from OIL's fields in North-East India. It has been under production since 1993, with 62% of the production coming from horizontal wells.

The drilling strategy of North Kuwait has embraced in the last few years to get more reservoir contact to maximize oil recovery. Presently, the wells are drilled with high deviation angle to intersect multiple pay zones and drain the existing prospects. However, water coning and edge water breakthrough are challenging to achieve production longevity. Inflow Control Devices (ICD) is a proved tool in oil industry, which can delay the water encroachment by creating uniform drawdown across wellbore section. The production performance of ICD wells indicated stability of water cut for longer period as designed. Answer products is the key to monitor downhole production profile to ensure the functionality of ICD units. Some reservoirs are suffering from pressure depletion and artificial lift (ESP) was installed to deepest point to increase pump efficiency. This type of completions is limiting accessibility to collect downhole data for further action. Besides, after period if the water shutoff is required, the well intervention inside ICD completion is challenging due to bore size limitation and materials availability. Proactive action was taken to utilize the advanced technology of ICD Completion, which allows faster execution of Rigless shutoff and reduce Rigs demands.

Deviated wellbores are more common-place in the industry in recent years as Maximum Reservoir Contact (MRC) is the preferred strategy in wellbore construction. These high-angle, tortuous wellbores, however, have now limited the artificial lift options to Electric Submersible Pumping systems which are capable of sustained life cycles in high-watercut, low-pressure, and/or low-rate completions. Production logging and Coiled Tubing intervention in multi-layered completions and/or multi-compartment horizontal laterals equipped with Electrical Submersible Pumping systems has customarily been a major challenge, especially when the bypass fluid velocities are below the motor-cooling threshold for a conventional Y-tool configuration. An innovative design comprising of a shrouded Electric Submersible Pump with Y-tool combination is able to facilitate access to any completion that requires production logging and/or CT intervention. At relatively low fluid rates, the shroud over the Electric Submersible Pump increases the fluid bypass velocity alongside the submersible motor for the required cooling. This shrouded Electric Submersible Pump configuration is conventionally used where the production flow rates within the wellbore are insufficient to generate the fluid bypass velocities necessary for optimum motor cooling. The Y-tool in other completions allows access for any type of wireline or Coiled Tubing-conveyed intervention for surveillance and and/or treatment operations. Previously, if a completion required a shrouded ESP, conventional Y-tools were precluded, due to the limitation of the production casing inner diameter. A specialty Y-tool was designed to accommodate conventional bypass tubing that has sufficient internal clearance for standard wireline tools together with a crossover adapter for the ESP shroud. This combination of conventional bypass tubing and Electric Submersible Pump shroud in the same wellbore, is limited to 9⅝″ casing where the shroud outer diameter and the bypass pipe outer diameter must have sufficient clearance between each other and sufficient stand-off from the inner diameter of the production casing. The Electric Submersible Pump shroud ensures optimum motor cooling and extended system run life, especially at lower flow rates. This innovative technology is now scheduled to be standard equipment in all Electric Submersible Pump completions in production casings with Outer Diameter equal to or greater than 9⅝″. Diagnostic wireline and Coiled Tubing-conveyed surveys, remedial and stimulation treatments can now be performed thru-tubing in Electric Submersible Pump completions without costly rig workovers. The availability of these services affords timely intervention to arrest increasing watercuts in Waterflood offtake producers thereby reducing the overall baseline production decline rate.

Polymer flooding is an attractive option in hydrocarbon maturation plans. Several successful polymer floods and pilots have been implemented. One of the risks in polymer flooding is loss of injectivity. The consequences of loss of injectivity can be large. In conditions where matrix injection is required, reduction of injection rate may result in a much slower propagating polymer front and consequently later arrival of the anticipated oil bank eroding on the economic value of the EOR process. In extreme cases it can even lead to loss of the injector. Under fracturing conditions the loss of injectivity may be less noticeable, but it can lead to out of zone fracturing or fractures that grow too much in size and cause shortcuts to the producers or affect future infill well drilling. Reduction of injectivity is a generic concern in conventional waterfloods and can play an even larger factor when adding polymer to the waterflood. The increased viscosity of the injected polymer solution is the most obvious reason for an anticipated decrease in injectivity, but also other mechanisms can have an impact. These mechanisms include excessive polymer adsorption and associated permeability reduction, filtration of impurities in the polymer solution, fluid incompatibilities or reduced water quality. In this paper we will discuss the various causes for loss of injectivity and propose a structured approach for the associated prevention and mitigation options. Prevention includes (1) selection of the most appropriate polymer type; (2) best practices for preparation of the polymer solution; (3) safeguarding the water quality; and (4) enabling options for mitigation in case excessive injectivity loss is observed. The remediation step includes (1) the identification of the root-cause of an apparent injectivity problem; (2) the design of an appropriate clean-up treatment; (3) monitoring of the operation; and (4) implement measures to avoid repetition of the problem. We will include an overview of the preventive and mitigation options for the different causes of injectivity decline in polymer floods.