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Well integrity assurance and zonal isolation, are the main pillars for any oil and gas well, it was a practice in the past to evaluate cement behind casings for casings smaller than 13 3/8 inch, however with the increase in drilling deeper and more challenging wells, the need for evaluating cement behind larger and thicker casings became a necessity.Different logging companies have invested in their existing cement evaluation services and upgraded their tool designs, specifications, and increased tool operating range to address the larger and thicker casing requirements. By mid-2016, the upgraded tool measurements range was extended to evaluate up to 22-inch.KOC in South-East asset started developing their Marrat deep reservoir back in 2018, these wells are designed with large surface casings ranging between (18 5/8-inch and 24-inch) across their main reservoirs (Burgan) and the shallow water and gas bearing formations (Dammam, Radhuma, Tayarat, and Mishrif). Dammam, Radhuma, Tayarat, and Mishrif formations, feature a highly fractured carbonate reservoir and comprise corrosive water and trapped gas pockets. The corrosive water and the trapped gas pockets pose future potential well integrity risks in the field, which implies the need for proper zonal isolation throughout the well and the field lifespan. These formations also comprise a low formation frac gradient, that raises the requirement for low-density cement ranging from 8.5 to 10.5 PPG to overcome the shallow loss zone.The newly developed extended range for the ultrasonic cement evaluation tools can cover up to 18 5/8 inch surface casings for KOC, however, some additional tests, work, and modifications were required to accommodate the 24-inch casing, which will be discussed later in this paper.

The Great Burgan reservoir is the largest sandstone oilfield in the world, it has been developed and produced since the 1930s. Historically developed through deviated wells, a new project of horizontal wells was initiated recently to produce from the UB3 reservoir unit. A pilot hole is usually required to identify the presence of productive sublayers and the depth of the oil-water contact (OWC), which must be avoided in the horizontal section. Elimination of the pilot hole would help to minimize the time and cost of development (Al Khalifa et al. 2020). The azimuthal ultra-deep resistivity mapping service (UDR) has proven its capability to eliminate the need for pilot holes by mapping reservoir boundaries and OWC on the fly, earlier than with traditional methods. This facilitates real-time geosteering to land the well in a single drilling run in the productive zone. Additionally, it helps to reduce non-productive time by making it easier to stop drilling and set casing above a target layer and to help optimize future well planning in field development. A feasibility study performed on offset wells showed promising potential from application of this method in the UB3. Real-time UDR geomapping detected multiple thin sand lenses on top of UB3 but showed that they were not of commercial capacity. The decision was made to continue drilling deeper for a larger sand layer. The UDR detected a massive sand below the smaller lenses and the well was landed in it. Early mapping also helped to optimize the landing with the desired inclination and dog-leg severity. The OWC was detected ~35 ft TVD below the landing point. Without UDR it would have been impossible to detect the OWC and very challenging to perform an accurate landing. The target could have been missed by landing either too shallow or too deep or with the wrong inclination. Following the landing of the well the lateral section was drilled through upper and lower lobes of the massive sand with a total cut of 1649 ft MD. This comprised 450 ft MD of upper lobe, 350 ft MD of transition interval, and 637 ft MD of lower lobe inside BU3, with an average porosity of 30 p.u. and a water saturation of less than 10%. Formation pressure tests measured mobility of up to ~3.4 D/cp. This case study demonstrates that utilization of the ultra-deep resistivity mapping service enabled a new approach to drilling lateral wells in the Burgan field development, improving reservoir insight and reducing well drilling time and cost.

Groundwater is the largest available reservoir of freshwater. But the rapid increase in the population and urbanisation, has led to over exploitation of groundwater which imposed tremendous pressure on global groundwater resources. Because of the hidden and dynamic nature of groundwater, it requires appropriate quantification for the formulation of groundwater planning and management strategies. The present study evaluates the efficacy of geospatial technology based Multi Influence Factor (MIF), Weight of Evidence (WofE) and Frequency Ratio (FR) technique to evaluate groundwater potential using a case study of basaltic terrain. The thematic layers influencing the groundwater occurrence viz. rainfall, slope, geomorphology, soil type, land use, drainage density, lineament density, and elevation were prepared using satellite images, hydrologic, hydrogeologic and relevant field data. Based on the conceptual frameworks of MIF, WofE and FR techniques these thematic layers and their features were assigned with appropriate weight and then integrated in the ArcGIS platform for the generation of aggregated raster layer which portray the groundwater potential zones. The results of validation showed that the groundwater potential delineated using MIF technique has a prediction accuracy of 81.94%, followed by WofE technique (76.19%) and FR techniques (71.43%). It is concluded that for evaluation of groundwater potential, the MIF technique is most reliable, followed by the WofE technique. The evaluated groundwater potential zones are useful as a scientific guide to identify the suitable location of wells and recharge structure in a cost-efficient way and also for the development of structured and pragmatic groundwater management strategies.

The primary objective of the study is to characterize the hydrogeologic status and identify the trend in groundwater storage of aquifer system to provide an improved understanding of the groundwater flow system in the Kadva river basin, India. This is accomplished by the integrated use of stratigraphic modeling, pressure derivative approach, and pumping test analysis. The results of the stratigraphic modeling indicate that the unconfined aquifer thickness ranging from 8.2 to 34.2 m and generally occur to the depth of 2.2–36.5 m below ground level (bgl), whereas semi-confined aquifer thickness ranges from 6.1 to 58.3 m and generally occurs 30.6 m bgl over the study area with an interconnected semi-confining unit of thickness ranging from 1.6 to 22.3 m. The pumping test results of unconfined aquifer in the study area show that the transmissivity varies from 15.66 to 98.18 m2/day, and the specific yield ranging from 8.2 × 10–4 to 3.2 × 10–2. Pumping test data and derivative analysis show that the deep aquifers are semi-confined with transmissivity ranging from 14.4 to 111.2 m2/day, storage coefficient varies from 1.56 × 10–4 to 4.83 × 10–4, and hydraulic resistance ranges from 93 to 1270 days. The values of hydraulic parameters revealed a remarkable spatial variability, suggesting that the basaltic aquifer system has strong heterogeneity. The results of the present study are helpful in the formulation of efficient policies for sustainable groundwater management in basaltic aquifers system in India in particular and worldwide in general.

Objectives/Scope The acquisition of mud gas data for well control and gathering of geological information is a common practice in oil and gas drilling. However, these data are scarcely used for reservoir evaluation as they are presumably considered as unreliable and non-representative of the formation content. Recent development in gas extraction from drilling mud and analyzing equipment has greatly improved the data quality. Combined with proper analysis and interpretation, these new datasets give valuable information in real-time lithological changes, hydrocarbons content, water contacts and vertical changes in fluid over a pay interval. Methods, Procedures, Process Post completion, Mud logging data have been compared with PVT results and they have shown excellent correlation on the C1-C5 composition, confirming the consistency between gas readings and reservoir fluid composition. Having such information in real time has given the oil company the opportunity to optimize its operations regarding formation evaluation, e.g downhole sampling, wireline logging or testing programs. Formation fluid is usually obtained during well tests, either by running downhole tools into the well or by collecting the fluid at surface. Therefore, its composition remains unknown until the arrival of the PVT well test results. This case intends to use mud gas information collected while drilling to predict information about the reservoir fluid composition in near real time. To achieve this goal we compared mud gas data collected while drilling with reservoir fluid compositional results. Pressure volume temperature (PVT) analysis is the process of determining the fluid behaviors and properties of oil and gas samples from existing wells. Results, Observations, Conclusions The reason any oil and gas company decides to drill a well is to turn the project into an oil-producing asset. But the value of the oil extracted from a single well is not the same as the value of the oil produced from another. The makeup of the oil, which can be determined from the compositional analysis, is an important piece of the equation that determines how profitable the play will be. The compositional analysis will determine just how much of each type of petroleum product can be produced from a single barrel of oil from that wells. Novel/Additive information Formation samples were obtained from offset wells in the Marrat Formation. These datasets gave valuable indications on fluid properties and phase behavior in the reservoir and provided strong base for reservoir engineering analysis, simulation and surface facilities design. The comparison of the gas data to PVT results gives a good match for reservoir fluid finger print, early acquisition of this data will help for decision enhancement for field development.

Neuman (Analysis of pumping test data from anisotropic unconfined aquifers considering delayed gravity response. Water Resources Research, 1975) method is an analytical solution suitable for unsteady flow of the wells that penetrate partially or fully in an unconfined anisotropic aquifer with a delayed gravitational response. The method is said to be valid when Sy/S > 10, for observation wells near the pumping wells where the drawdown observations made after adequate long pumping time. Although the method is widely used, the impact of using the Neuman (Analysis of pumping test data from anisotropic unconfined aquifers considering delayed gravity response. Water Resources Research, 1975) solution for interpretation of multiwell pumping aquifer tests data is barely discussed. In this chapter, the study examines and discusses the effect of using the Neuman solution for interpretation of multiwell pumping aquifer tests. It is accomplished by the simulation of two different homogeneous single-layered unconfined aquifer model’s as it is not easy to analyze in the heterogeneous condition since the transmissivity everywhere can differ naturally with the location of an aquifer. MODFLOW numerical modeling has been used for the time-drawdown simulation and interpreted the results using the Neuman solution. The study concluded that under the control of Neuman equation, the transmissivity interpreted from an observation well with an increase in radial observation well distance appears as increasing exponentially and in case of specific yield, it is observed as decreasing due to its less responsive nature to influence of the observation well distance. The study is helpful for the application of Neuman solution to the interpretation pumping test data at different radial distances of multiwell aquifers.

Studying the flow behavior in horizontal section addresses further challenges and complexity. Innovative technologies were developed to overcome the fluid segregation challenges in horizontal sections and cover the entire production profile. In Kuwait, horizontal production logging is typically conveyed on 1.75" electrical coiled tubing which is relatively large size and therefore increases the risk of choking the well or killing low flowrate wells. Also, there is a limitation on the availability of the electrical coiled tubing. Greater Burgan smart ICD wells require a periodic assessment of the production profile and the contribution from each port to overcome the increasing water cut challenge in such a mature field. To identify the source of water, the engineers planned a new strategy to minimize the choking effect through use of smaller coiled tubing size. However, the available small size coiled tubing are not equipped with an electrical line for real-time data streaming. This challenge was resolved by opting for a horizontal PLT logging recording in a memory mode acquisition. Running the production logging in memory mode is not unusual in vertical and slightly deviated wells, but it is not common in horizontal wells. Risk assessment was carried out trying to eliminate all the expected obstruction such as having a dummy run while monitoring production behavior on the surface using a testing unit, reducing the coiled tubing speed to avoid disturbing the flow stabilization and watching for any indication of coiled tubing tension-compression changes. A contingency plan was in place, for carrying out a nitrogen activation in case the well chocked below the accurate reading limits during the logging. Following the detailed steps and extensive planned procedure, the logging with memory mode in the horizontal section was successful and resulted in accurate flow profile determination along with contribution from each ICD ports. Using normal coiled tubing instead of the electrical coiled tubing has resulted in reduced operational cost and eliminate the challenge of the limited availability of electrical coiled tubing that was delaying the PLT jobs. The major production logging output was accurately presented from the memory mode. This paper includes the challenges from using memory production logging in horizontal section. A risk assessment for each of the challenges and contingency plan to apply this method.

Meeting 2040 KPC Strategic plan objectives and KOC production targets will require adoption of new cost-effective technologies and methods in Kuwait fields, resulting in incremental oil production and extended life of the fields. Long-term oil production through artificial lift application can lead to pressure depletion and water cut incremental in mature fields, which can cause obvious wellbore impairments, particularly in medium to week formations such as Wara and Upper Burgan formations. One of the critical parameters that will have great influence on maturing this strategy is sand management-field development. Recently some of high producing wells perforated in Wara sandstone Formation in the Greater Burgan field in Kuwait have been plugged due to sand production issues. Understanding the causes of this critical challenge will definitely help KOC in finding the optimum sand management work flow and select the right sand control technologies to maximize the oil production in Wara formation. Several sand characterization tests were conducted on core plugs and produced samples collected downhole, ESP wellbore data was linked with well logs analysis and production data for understanding the sand production phenomena within the intervals and help establish a sand collapse model. Based on the lab work, modeling and ESP real time data, a screening benchmark was developed for sand management and control for Wara formation. The unique customized screening criteria will support South East Kuwait (SEK) field development to identify/avoid the potential sanding intervals and sustain oil production at safe drawdown pressure, which definitely will prevent ESP failures and extend the ESP lifetime. The risk assessment for potential sanding intervals has been established to predict sand production in most new Wara wells. Some Wara wells targeting shallower or weaker sands would normally be sand control candidates, by taking into account the completion design, optimizing surface sand management workflow, managing safe drawdown and BHFP levels, and taking advantage of favorable stress vectors through oriented perforation can encompass the sand free well operating envelopes over life of well production and depletion conditions.

Kuwait Oil Company initiatives for ushering in a new era of digital transformation of its assets to intelligently and optimally manage the Oil and Gas fields were successfully realized with the completion of three pilot projects entitled Kuwait Integrated Digital Fields (KwIDF). This paper discusses major achievements of the Digital Oilfield technology implemented in Burgan KwIDF project and provides an insight on the challenges in operating it. The Burgan KwIDF pilot successfully transformed GC-1 production asset into a fully instrumented DOF comprising of digital instruments and infrastructure installed at well site and the production facility. Real-time production data is transmitted to a state of the art collaboration center that integrates data continuously with automated workflows for validation, modeling and tuning of well and facility models. Right time decision support information generated from smart visualization tools allow quick actions for production optimization, well and facility management in a collaborative work environment. There is persistent value realization from KwIDF technology implemented in Burgan field. It has generated substantial cost savings with faster response time in restoring production and reduction in non-productive time. Driven by the digital environment asset production has sustained at target as production gain opportunities are capitalized and losses compensated quickly. Over the period of time with experience in utilizing the DOF technology it has been observed that the technology sustainment is dependent on the technology providers to a large extent. The main components that require their continuous support are the digital instruments, proprietary software, hardware and related infrastructure. Technical expertise in each domain is necessary for ensuring continuous and smooth operations in the field, wellsite and collaboration centers. Development of an integrated team of domain experts is crucial for successfully managing the DOF operations. Change management initiatives for developing an in house user champion team is mandatory for ensuring sustainment. The important lessons learned and solutions are discussed in detail.

The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs. The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels. This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.

Oil and gas companies face major challenges for meeting increased energy demands around the world. There is a sharp decline in production from existing fields and at the same time, discovery of large new fields has become increasingly difficult. As a result, oil and gas operators around the world are implementing various strategies to find ways of increasing recovery from existing reservoirs With ultimate average recovery factor for oilfields on a worldwide basis of about 35%, companies are trying to improve recoveries through new technology initiatives such as integrated digital oil field approaches, which integrate reservoir and production system together for continuous monitoring of asset performance and production; optimization, and control of wells and fields. Comprehensive workflows and collaboration environments are key elements of any successful digital oil field operation. They integrate a multitude of data sources and applications, capture the knowledge of production processes, and enable improved decisions. These workflows help overcome the complexity of today’s asset management operations. Kuwait Oil Company implemented such initiatives in one of its assets in Burgan oilfield which involved instrumentation at well site, a SCADA system for data acquisition and control, integrated asset management workflows together with state-of the art collaboration center enabling faster diagnostics for well and facility performance. The integration of surface and subsurface models in an automated workflow process allows quick review of well health and assists in planning for short- and long-term production optimization actions.

The mature Greater Burgan field is the largest clastic oil reservoir in the world producing from multiple clastic reservoirs. With growing surface area congestion affecting rig moves, current wells are drilled with high deviation often through unstable overburden shales. Well trajectories are getting more complex, resulting in a large increase in hole instability events associated with stuck pipes, loss of bottom hole assemblies often leading to side-tracks, challenging well logging conditions and well completion operations. This paper discusses a holistic and practical geomechanical approach to solve the instability problems, based on understanding the rock failure mechanism of shale, and also discusses the implementation of an integrated solution to drill, log and complete the wells successfully. A thorough geomechanical analysis was done on several wells. Drilling data analytics helped to understand the relationship among formation instability, well trajectory and mud parameters. Lab tests (chemical and mechanical) were performed to determine the chemical and mechanical behaviour of the rock and its interaction with drilling fluid. Anisotropic shale strength tests were targeted to know the rock strength variation with respect to angle of attack. Geomechanical models were prepared and calibrated with observations of drilling problems. Based on integration of models and experiences, effective solutions were devised to implement at well planning as well as drilling stages. A combination of measured and modelled parameters suggested that multiple failure mechanisms are active to induce shale failure including (a) stress induced borehole breakouts, (b) chemoporoelastic interaction of mud and rock fluid and (c) weakening of shale bedding planes and micro fractures. A customized real-time geomechanical monitoring solution was implemented for improved drilling performance and efficient completion of new wells. Specific mud design and mud weights for drilling high angle wells (65-70 deg) were generated and used in real-time while drilling. With the help of LWD and mud logging data, real-time decisions were taken based on well behaviour to drill the wells in a single casing section. Wireline logging and lowering of completion string was completed without any resistance even after the long section of shale was exposed for several days. This entire re-engineering of the process was accepted as a cost-effective and efficient solution that is being recorded as a best practice for implementation in future wells. Integration of diverse disciplines (geomechanical, geochemical, petrophysical and drilling engineering) was successfully implemented to drill a complex well. Real-time geomechanics along with customized drilling fluid and drilling practices enhanced the drilling efficiency. This integrated solution is expected to significantly reduce non-productive time in future upcoming wells with complex well profiles.

This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (P-CPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention. The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The P-CPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant. The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive. In high-permeability and low-pressure reservoirs, several unsuccessful attempts can extend the intervention by two or more weeks. CPS and P-CPS systems provide a predictable and controllable right-angle set time that can help to ensure sealing on the first attempt. These systems do not develop compressive strength, simplifying the cleanup stage by quickly and easily jetting it out of the wellbore with coiled tubing (CT), as opposed to cement that must be drilled/milled out. This paper describes laboratory evaluations, treatment design methodologies, and two case histories from Kuwait, including one well that produced 1,600 BOPD after reperforations.

The asset optimization system deployed in Kuwait's Greater Burgan oil field involved development of an integrated model of the processing facility, flowlines and wells. The objective of the integrated asset model is to achieve production optimization from the network considering well performance and restrictions combined with the limitation imposed by the surface piping network and the processing facilities. The Burgan oil field's integrated digital field (KwIDF) automation system monitors well and plant instruments in real time from SCADA and DCS systems. It uses real time wellhead pressure and water water-cut measurements for virtual metering and calibration of the well and network models. To maintain the facility production target, various built-in production optimization scenarios are run daily and the results are visualized through smart dashboards in the state-of-the-art collaboration center. The results are shown as new optimized set points for choke or header changesto achieve facility production targets. The new set points can be automatically passed on to the SCADA system for implementation after quick validation by the stakeholders. The paper provides new insights on the challenges of effectively running an integrated well and network model in an automated workflow through full loop, from measurement to implementing recommendations at wells and the production facility. Examples are presented on 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 at Greater Burgan field in Kuwait.

One of the first sources for formation evaluation while drilling a well is the gas data provided by the mud logging services, that is used increasingly as preliminary real-time reservoir interpretation to identify gas-oil or oil-water contacts, reservoir entry points, lithological changes and other applications. Gas ratio analysis and interpretation is a very valuable formation evaluation tool for geologists and petrophysicists to characterize the hydrocarbon fluid types and rock properties. Gas ratios when used in combination with wireline or logging while drilling tools can help resolve uncertainties that otherwise could only be resolved by testing a well. Jurassic deeper wells (>11000 ft) with a varying pressure regimes, very often the wireline logging or Logging while drilling (LWD) logs are cancelled due to several drilling related complications especially mud gain/loss situations. In these wells, Gas while drilling becomes a very unique and important tool that can provide significant insight into the reservoir properties. The gases liberated from the formation at the surface helps us determine the composition of the reservoir fluids and also provides information about the lithological changes, water saturation, and the mobility of the hydrocarbons contained into the rock. This broad spectrum of hydrocarbons assisted by the surface gas analyzer allows the separation of producible mobile heavy hydrocarbons from water wet zones. This ability to differentiate allows operators to geosteer a horizontal well in thin units of potential reservoirs by avoiding water bearing zones and staying in producible hydrocarbon zones. The end result is the ability to intersect the maximum amount of net pay in the target zones. This paper highlights the case studies from deeper reservoirs of East Kuwait where a surface gas logging system employing a semi-permeable membrane extractor coupled with an advanced GC tracer chromatograph detector has been applied in some of wells drilled in Greater Burgan Magwa Marrat limestone reservoir. Advanced gas logging system was deployed in two vertical/deviated wells to characterize the gas ratios for the different units/zones of Marrat reservoir. The zonation from Gas ratio interpretation was validated with the available wireline logging data before using it for planning the horizontal well. The GWD and LWD were performed independently of each other to determine the effectiveness and reliability of the GWD method. GWD in conjunction with LWD was used for the first time in Kuwait to place a horizontal well in a thin (15-20 ft) layer of a deep Marrat reservoir. Use of realtime Gas ratio data and analysis, successfully helped to complete the well as planned high producer.

Productivity remains an intriguing subject and a dominant issue in the construction sector, promising cost savings and efficient usage of resources. Productivity is one of the most important issues in both developed and developing countries. The developed countries are aware of the importance of economic growth and social welfare. The developing countries which face unemployment problems, inflation and resource scarcity seek to utilise resources and in such a way as to achieve economic growth and improve citizens’ lives. The aim of this thesis is to identify factors affecting labour productivity and also to study causes i.e. labour problems on site and its effects on the construction projects. Some of the important factors affecting labour productivity are: quality of site management, material shortage, timely payment of wages, labour experience, misunderstandings between labour and superintendent etc. The problems faced by the labour on Indian construction sites are dealt with in detail. Problems like non-availability of proper accommodation, basic amenities, low wages, safety related problems, security etc. dominate on almost all Indian construction sites. In our survey we have found that, specifically small firms in India are not able to fulfill labours’ requirements. And that is why labour is not able to raise their productivity. In fact it is found that actual labour productivity ratios are reducing day by day, which in turns harms organization’s profitability. In this study we will try to relate the ill effects of labour productivity this study restricts itself to the survey and research in the Indian context. Analysis of obtained data was done using different statistical methods. This report includes explanations on productivity, a case study, factors affecting labour productivity and the remedies for the same.

The Burgan KwIDF technology comprises of instrumentation and infrastructure installed on the wells and production facility to monitor production in real time. Data from wells and production gathering facility is transmitted to the field operations center through SCADA and also to the base collaboration center where it is processed and analyzed within the Burgan KwIDF intelligent daily operations system (i-DO). The KwIDF system has automated workflows which generate a real time alarm from the raw data based on anomaly detection and exceeding of operational thresholds. Smart dashboards are also provided which processes raw information for quick indication of production losses or gains from wells and associates it with the key change in well or facility parameter. Opportunities for increasing chokes or header changes are proactively presented for compensating losses and increasing production utilizing integrated well and network models with the real time data. This paper provides insight on the application of integrated digital oil field technology in Burgan field. It shows through actual field examples how real time data integrated with smart automated workflows and intelligent alarms help in improved well diagnostics, enable quick actions to minimize losses, sustain and increase production with effective facility and water management in a collaborative work environment.

Greater Burgan Field accounts for most of the oil produced in Kuwait. Discovered in 1938, commercial production from this giant field commenced in 1946 accelerating rapidly to a peak of nearly 3 MMBOPD in 1972. The Burgan structure is an anticlinal dome with numerous faults. The main producing reservoirs are sandstones of Cretaceous age. Four major sandstone horizons within the gross productive section account for most of the current and cumulative production. The 3SM is the main contributory sand which is much thicker than the others. A strong natural water drive maintains reservoir pressure. The compartmentalization of the main reservoir sands by faults, combined with high production rates, resulted in water incursion problems since the early seventies and made worse by uncontrolled flow from wells sabotaged during the Iraqi invasion. As the 3SM reservoir gets further depleted, water encroachment studies reveal that there is a differential rate of rise in OWC in the massive sand implying un-even sweep. This has created uncertainties in the remaining oil column in flank areas of the field for placement of infill well locations. This paper presents a methodology applied to successfully identify infill well locations in flank areas of Burgan field. The behavior of faults and rise in water in different compartments were analyzed utilizing seismic surveys, pressure buildup tests and PNC log data combining with production history. Based on the analysis minor faults were characterized and mapped which led to identification of unswept areas where new well locations were proposed. Gross pay found in three new infill wells drilled have been very encouraging. The process leading to identification of these successful well locations is discussed in length. More infill locations and well intervention opportunities are being identified by using this methodology with increased surveillance to further enhance production from this field.