We believe our prime responsibility is to protect the environment by utilizing the energy in a responsible way and also by reducing the wastage of energy. Energy conservation will play a vital role in climate change and leave our planet pristine for the next generations to come. In light of our Company’s ambitious vision of reducing energy consumption and losses and to conserve energy without disturbing the regular business of the Company, we have started to evaluate all the options to conserve the energy by incorporating the latest technologies, conducting awareness programs and optimizing the energy consumption. In line with our objectives, we conducted a study on one of the existing office building to check all the possibility of reducing energy consumption without disturbing the regular activity. At the end, we realised that the simple and easy way to conserve Energy is through conducting an Energy Audit and implementing Energy Audit recommendations.

Production operations and optimization strategic competencies are critical for effective business performance in operating companies that are transitioning from primary/secondary recovery to tertiary recovery or when the number of field development projects for non-conventional oil, become a significant percentage of their future oil production targets. This paper presents a practical approach for identification, definition and measurement of ten strategic competencies required to meet requirements of operations and optimization of heavy oil assets. The competency development model uses a fast track on the job learning approach that takes between 6 months to 1 year to reach a minimum level of performance. The identification of competencies is activity-based considering analog heavy oil fields undergoing improved oil recovery operations. Model is organized into 8 phases: 1) Data review to assess uncertainty, 2) integral reservoir review, 3) integral well review and nodal analysis, 4) identification of opportunities in drainage area, completion, production methods and surface, 5) selection of integrated solutions combining technology options, 6) economic analysis within exploitation plan 7) production optimization project definition, 8) production optimization execution and evaluation. Each phase undergoes activities with relative duration followed by decision gates with relative contribution of disciplines grouped in 10 functions (well productivity, production methods, surface processes, reservoir, geology, well construction and maintenance, integrated automation, health, safety & environment, reliability and activity based project and costing). Ranges of weights in percentages and duration are calibrated using analog fields or typical projects, as input for stochastic modeling to account for uncertainty. The application of this approach in heavy oil fields in Kuwait, allowed identification of technical competencies classified under 10 functional competency groups under four major categories: Subsurface-reservoir, subsurface-well, surface facilities & production operations and asset integration & planning. These technical competencies were mapped with three scenarios for intensity of work: minimum (low), medium (likely) and maximum (full) to conduct critical activities on annual basis during the heavy oil field life cycle. Worldwide heavy oil analogs provide foundation to validate and calibrate the model, and then used as planning tool. The model allows stochastic modeling of person-hours and cost of work force, including the competency development and assurance, included in Capital and Operational Expenditures as part of the economic model for evaluation of heavy oil optimization opportunities. The presented approach is a practical tool for mapping required competencies and intensity of work force for more reliable subsurface-surface integrated production operations of heavy oil fields. The phased model allows easier planning and flexibility to conduct exercises with estimates of work force for a range of potential business scenarios.

Industry 4.0 is also referred to as ‘the fourth industrial revolution’, reinforced by the rapid growth and development of the Internet of Things (IoT). Industry 4.0 represents the real-time digital integration of suppliers, products, equipment and customers, which brings many benefits including improved efficiency, lower costs, higher revenues and increased innovation [ 1 ]. Therefore, in this paper Kuwait Integrated Petroleum Industries Company (KIPIC) deploys a readiness multilayered framework and benefit metrics models to build the foundation and roadmap for successful progress towards Industry 4.0. KIPIC, with the privilege of being a greenfield company, intends to establish foundations for digitalisation and an integrated layer for all of its facilities, including Al-Zour refinery, petrochemical factory and liquefied natural gas. In this paper, a mixed of methodologies were used, including analysis of the literature, expertise and interviews with KIPIC CEO, DCEO(s), Managers and Team Leaders.

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.

Welcome to the future of ERM transforming from descriptive to analytic data for the risk register as the main objective because the risk register without statistical analysis equates to myopia, like a Heliographic Alphabet without the Rosetta Stone to translate. The scope of this paper is to demonstrate a statistical approach for the risk register where until now decisions have been made on descriptive data. A proactive analysis is used in this paper to analyze the risk register data that will enhance our understanding of the risk register’s items to subsequently make better decision. The approach is to quantify the descriptive data in a statistical platform called SPSS (Statistical Package for Social Sciences). The quantified data is first tested using Coefficient Alpha analysis. Coefficient Alpha measures the reliability of the coded data, that is the accuracy level of the likelihood and impact items in the risk register. Coefficient Alpha is a matric that attempts to reflect our mindset or cognitive level during the risk assessment phase. Reliability is expressed as a number ranging between 0 and 1, where 0 indicating no reliability (much error) and 1 indicating perfect reliability (no error) ( Peter 1979 ). The result of Coefficient Alpha analysis is a composite score (%) to aid whether to progress to the next stage. The entire coded data is uploaded to the SPSS platform or Microsoft Excel to analyze the data for correlation and regression of the assessment items that affect the risk degree in the risk register. From observations related to the scale of likelihood with impacts levels, and the chosen items should be revised because their correlations will be in degradation mode after time. The new method is wider than the current approach, leading to better decisions about how to treat high and very high risks. In the new method the risks to be treated will be selected based on which items from the evaluation list are most affecting the risk degree. The new method can form a comprehensive of risk management. This will enhance our understanding of the risk register in the petroleum industry, enhancing reporting, as well as removing some evaluation items that have no effect on the risk degree and adding alternative items in the risk register.

This paper demonstrates the efforts in mitigating uncertainties and minimizing risks while monetizing hydrocarbon and evaluating its evacuation in a highly integrated and complex offshore network environment by means of integrated network modelling approach. In oil and gas industry, it is always a challenge to determine the best evacuation path for a new offshore development tying-in to an existing infrastructure complex that has a network of more than 80 gas fields, 100s of export pipelines, multiple hubs, highways and receiving terminals. These network also has varying degree of ullages and bottlenecks as well as dissimilarities in accepted level of gas specification and blended fluid quality. Having a standalone development with its own dedicated evacuation infrastructure to shore would be a safer option but it may not be cost prudent in a highly competitive market. Tie back options to an existing complex network would entails uncertainties and risks in the evacuation path such as ullage unavailability, pressure imbalance, ambiguous performance of critical elements, the potential violation of the facility constraints, uneven flow distribution (reverse flow, cross flow) as well as infringement to the end product specifications commitment. These may result in (a) concerns for system operability (b) vague results of end product specifications which may pose a threat in designing a production plant and facilities improvement requirements as well as firming up investment decisions for offshore development. It is essential to evaluate these uncertainties and risks in a complex network by performing circumstantial analysis to cater for technical requisite prior to determining the evacuation route for a new development tie-in. It was apprehending that the availability of relevant simulation model for an integrated system in the market is limited hence a different approach was considered. A steady state network model that caters for an end to end value chain for a complex offshore network was developed using available tools from the industry. These integrated network model was validated against actual data and then deployed to optimize the evacuation options for new development tie-in to the existing network. Multi-faceted scenarios were evaluated in coming up with evacuation options considering system ullage, pipeline hydraulics (adhering to first principles), honoring the end product specifications commitments and network constraints. Sectionalization of sweet and sour gas corridor was performed and analyzed for these multiple tie-in options using the integrated network model and derived its effects on the overall network. It was assured that system parameters such as operating pressure, velocity limits and required specifications for the selected scenarios honors operating envelope and product specification commitments. It was demonstrated that the integrated network model could optimize the best evacuation route in terms of technical and business requirements, has resulted into monetization of new offshore development. Impediments (uncertainties and risks) across network in terms of ullages, pressure imbalance, system constraints, cross flow, reverse flow, violations in the Gross Heating Values (GHV), CO 2 levels etc. at terminal were forecasted as outcome from the model and its mitigations such as change in operating strategies, alternations in the evacuation path, modifications in the offshore network, was planned much in advance and was implemented accordingly. Uniqueness of this concept is the ability to attain an optimized hydrocarbon evacuation route within the existing network with minimal changes to operating philosophy. A holistic solution was achieved by eliminating the dependancies on the multiple applications for optimization at various levels of integration. Output from the simulation suggested on the alleviations that lead to CAPEX optimization by letting new development evacuation within existing system boundaries.

This paper aims to describe an evolving system utilised by young professionals with varying degrees of experience and backgrounds, supported by senior staff, to gain an improved understanding of ongoing well operations. The program has been tailored to the needs and capabilities of the individual, whilst allowing for continued development. Kuwait Foreign Petroleum Exploration Company (KUFPEC) has several joint venture assets across the globe. In order to assist in the communication with the Kuwait Head Office, KUFPEC has Area Offices to liaise with, and shadow the work carried out by local in-country Operators. However, by doing so the opportunity for Junior Staff, in the Head Office, to be directly involved in Well Operations is restricted. In order to mitigate this, a workflow has been initiated by the South East Asia Region (SEAR) that allows for Junior Staff to track the progress of wells being drilled and by doing so obtain a ‘feel’ for being in an ‘Operational Environment’. The workflow itself is flexible and has been tailored to the individual as well as specific well operations. In all cases the starting point is establishing the Well Objectives and so a detailed review of a Drilling Program and costs, followed by a Q&A session, is undertaken alongside more Senior Engineers to ‘introduce’ the well. Prior to Spud, ‘Well Montages’ are developed that describe the full information of the operation. The Well Montages are updated daily via Daily Drilling and Daily Geological Reports. An ‘Operational Highlights’ email is communicated to the department each afternoon that summarises the well progress and includes any risks or hazards to be aware of. Throughout the operation the Junior Staff are encouraged to reference the Drilling Program to follow the operations progress. After well completion a short ‘End of Well Summary’ is produced. Initial results of this workflow have been extremely positive. As more wells pass through the workflow the technical understanding of the Junior Staff increases. Their appreciation of specific hazards and uncertainties has improved, and they also have gained an enhanced understanding of Well Operations as well as the associated terminology and abbreviations. Support for the Junior Staff has also been obtained from the Area Offices, who are in direct contact with the operators. This paper would be of interest to Mentors or Coaches who have an emerging talent pool. The paper outlines a clear and concise method that has been tried and tested and that allows for a Coach to define a workplan specific for the needs of the Junior Engineer, and thereby promote their individual development needs whilst on the job.

Tracer technology is an efficient and effective monitoring and surveillance tool with many useful applications in the oil and gas industry. Some of these applications include improving reservoir characterization, waterflood optimization, remaining oil saturation (Sor) determination, fluid pathways, and connectivity between wells. Tracer surveys can be deployed inter-well between an injector and offset producer(s) or as push-and-pull studies in a single well. Tracers can be classified several ways. (a) Based on their functionality: partitioning and passive tracers. Partitioning tracers interact with the reservoir and thus propagate slower than passive tracers do. The time lag between the two types can be used to estimate Sor, to ultimately assess and optimize EOR operations. (b) Based on their carrying fluid: water and gas tracers. These can be used in IOR or EOR operations. All gas tracers are partitioning tracers and the most common are perfluorocarbons; they are thermally stable, environmentally friendly, have high detectability and low natural occurrence in the reservoir. On the other hand, water tracers are passive tracers and the most commonly used ones are fluorinated acids. (c) Based on radioactivity: radioactive and non-radioactive tracers. Selecting a tracer to deploy in the field depends on a number of factors including their solubility, fluid compatibility, background concentration, stability, detectability, cost, and environmental impact. This paper provides an overview of various tracer applications in the oil and gas industry. These will include the single-well tracer test (SWCT), inter-well tracer test (IWTT), nano tracers, gas tracers and radioactive tracers. Their use will be highlighted in different scenarios. Field case studies will be reviewed for all types of tracers. Lessons learnt for all the applications, including what works and what does not work, will be shared. Specific cases and examples will include the optimization of waterflood operations, remaining oil saturation determination, flow paths and connectivity between wells, and IOR/EOR applications. The current state-of-the-art will be presented and novel emerging methods will be highlighted. This paper will showcase how the tracer technology has evolved over the years and how it shows great potential as a reservoir monitoring and surveillance tool.

We propose a design for securing machine-to-machine (M2M) communications for field connected IoT devices by using the blockchain technology for digital identity management. Our approach considers a fundamental issue with public key cryptography, which is certificate issuance, revocation, and distribution. The blockchain design eliminates the need for a single authority for identity management and provides security by design for digital identity management and distribution.

The aim of this study is to understand the effect of choke management strategies on the productivity of a Multi-Frac Horizontal Wells (MFHW) completed in a liquid-rich (gas-condensate) unconventional reservoir. The focus is the investigation of the how controlling drawdown during depletion impacts the formation, extent and structure of a condensate bank near the multiple fracture faces and how controlling bank formation through controlling drawdown influence productivity. Analysis of these productivity impacts was used to evaluate the most effective choke management practices in ultra-low permeability gas condensate reservoirs. Several fine grid compositional simulation models for MFHW completed in ultra-low permeability gas condensate reservoirs were developed. Parametric simulation studies were then performed using fluids with varying descriptions (e.g. dew point, initial CGR), varying reservoir properties (e.g. reservoir pressure, reservoir permeability) and varying well completion characteristics (e.g. fracture conductivity, distance between fractures). Condensate bank development was monitored in these simulations for various choke management scenarios. The effectiveness of each choke management scenario was evaluated and the best approaches were identified. There exists a misconception that for gas condensate produced from unconventional reservoirs, there is no benefit in managing drawdowns through choke adjustments. This misconception rises from the idea that in an unconventional gas condensate reservoir, large drawdown is required to produce the gas, and as a result, the pressure must fall below the dewpoint nearby wellbore and a degradation in performance due to condensate banking cannot be avoided. The results of our study show that, in some situations, the liquid recovery and cash flow per well can be maximized through choke management resulting in controlling the size and form of the condensate bank created. The main determining parameters is initial reservoir headroom (p i − p dew ) and drawdown (p dew - p wf ). If the head room is high, or intermediate, there is value in choke management, i.e. controlling (p dew - p wf ), for both maximizing liquid recovery and also cash flow. However, if head room is essentially zero, then it is better to open the choke fully, i.e. maximize (p dew - p wf ), from the beginning. In this last case, there is still a small incremental benefit in choke management if maximizing oil recovery is the primary value driver. This study shows that we can produce at BHP below dewpoint and still have CGR (t) remain a large fraction of initial CGR for significant producing times. The trick is to produce the well at condition close to succession of steady state. In this case, the size of the condensate bank remains compact, controlled and often relatively small over the production time of interest. This condition can continue until end of fracture linear flow regimes and beginning of Pseudo boundary dominated flow regime when the whole SRV goes to depletion mode. Note these results show that standard PVT descriptions can produce CGR(t) close to initial CGR for long periods during production and imply that dewppont suppression due to confinement in small pore spaces is not always required to achieve this.

The Umm Gudair field is an elongated doubly plunging anticline which bifurcates into two branches NS elongated West UG and the NE-SW elongated East UG structures with a broad saddle in between Fig1A & 1B . West Umm Gudair structure was formed during the Jurassic time and become reactivated in Cretaceous and Tertiary times. East Umm Gudair was formed during Cretaceous as evident from the thicker deposition of overlying Gotnia sediments and its unique fold geometry. A total of 28 wells targeting Najmah-Sargelu (NJ/SR) & Marrat reservoirs of Jurassic have been drilled so far in this field including one deep well in South UG in Divided Zone The Marrat Formation in Umm Gudair field is conventional reservoir with 800ft to 1000ft thick sequence comprising limestone, dolomitic limestone and argillaceous limestone with minor shale and anhydrite. The Jurassic sequence in Kuwait oil fields starts from around 12000ft and is marked by an increase in formation pressure and temperature. Above this lies the Cretaceous sequence where most of the oil field development works have been concentrated in the past. In the last two decades field development has extended to the Jurassic sequence to meet up with increasing production demands. The Jurassic sequence is marked by a series of high pressure and high temperature formations with presence of natural fractures.

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 ever more challenging environments in which new wells are to be drilled, the uncertainties of the current market, and the availability of effective secondary and tertiary enhanced recovery (EOR) technologies, make the extension of existing wells' life more advisable than drilling new wells. To properly and proactively manage the degradation of Well Barrier Elements (WBEs) over time, thus ensuring the extension of wells life, a specific methodology and software have been developed. The concept of "Wells Life Extension" not only requires to get an adequate knowledge of the current wells integrity status, but also to predict future critical WBE(s) in order to put in place ad-hoc preventive measures. The methodology described in this paper includes three main phases: Well Integrity Assessment, which evaluates today's well integrity status through a risk-based approach. Estimation of Wells Ageing, which estimates the residual well life based on the understanding of WBEs ageing mechanisms. Definition of Intervention Plan Options, in which wells are classified on the basis of specific parameters, and then prioritized for future interventions through a cost-benefit analysis. The implementation of such methodology has allowed Customers to find out the most appropriate actions to be carried out on their ageing wells, with the objective of keeping production performances and safely operating the wells in line with the planned targets. Moreover, it has enabled to properly plan such actions over time, on the basis of the risk levels associated to the failure modes of each WBE, thus preventing and mitigating the need of potentially expensive interventions and protracted downtimes. Furthermore, emergency situations that would even increase costs and/or failures impacts, have been prevented, mitigated, and proper monitoring and maintenance programs have been executed in order to manage risks over time. In summary, the overall benefit of the presented methodology and software consists in anticipating well integrity issues and extending wells life through a proactive and cost-effective approach, that can enhance assets reliability, improve safety levels and minimize both downtimes and costs associated to WBEs failures.

Over the years, cybersecurity threats have grown significantly, and securing Operations Technology (OT) assets is one of the biggest challenges within the oil and gas industry today. Poor security policies could lead to unauthorized access to business-critical assets, confidential information leakage and result in business disruptions causing HSE, financial, and reputational impacts. This paper details how advanced and robust security policies shall mitigate cybersecurity risks and enable a smooth execution of Digital Oil Filed (DOF) projects and other complex O&G projects involving high convergence between IT & OT environments. The DOF projects include integration of Industrial Control System (ICS) network with corporate network at various levels, and this mandates consideration of multiple layers of security controls to implement a defense in depth strategy in order to secure ICS & Corporate infrastructure. It includes establishment of an integrated governance model that orchestrates the Cybersecurity Management System (CSMS) that encompasses IT & OT, define a secure architecture for ICS, lay enforcement zones to segregate ICS network from the Corporate/ Enterprise network by enabling strong firewalling/ intrusion monitoring policies, perform continuous monitoring and develop response capabilities to combat cyber-attacks/ intrusions. Additionally, the awareness level of the entire workforce should be escalated to ensure they are ‘cyber risk-aware’ and comprehend how crucial it is to incorporate ‘security sense’ at work. Since cyber-attack aimed at ICS environments heavily leverage physical security weaknesses to introduce a cyber-physical impact, it is quintessential to consider robust physical safeguards to protect marshalling rooms, control equipment, and the overall perimeter of facilities. The "security" factor for DOF primarily focuses on the availability of the systems, minimizing downtime risks which is of paramount importance for Oil & Gas business. This paper focuses on KOC's comprehensive approach to secure its critical assets within DOF which comprises people, process and technology components that contribute towards achieving KOC's business objectives.

The aim of this paper is to outline a fast and reliable workflow that allows delivering a rapid and high-level evaluation of reservoir performance based on surveillance data. Exploration prospects, single well analysis and quality control of full field models are typical opportunities for the application of fast track evaluations. The integration of data in simplified workflows is a sufficiently robust approach to provide reasonable analyses, mainly where time and resources are limited. To illustrate the fast track process, petrophysical and well test evaluations are combined to generate sufficient information to enable the prediction of reservoir performance using a very simplistic and optimized workflow. Wireline data and information from permanent downhole pressure and temperature gauges are used to assess well performance and to forecast potential reservoir offtake. To test the effectiveness of the workflow, a case study from a field in Europe has been carried out. Well production testing is extensively used during the appraisal stage, to build confidence that hydrocarbons can be commercially produced, and during field development, to monitor well productivity performance through time. Using well test analysis (WTA) reservoir characterization, reservoir container volume, depletion mechanisms, reservoir connectivity and distance of wells to boundaries can be addressed, using as input, petrophysical, geological data and fluid properties. Petrophysical data is fundamental to the evaluation of well potential and the identification of possible productivity issues related to well integrity and/or formation damage. A pressure derivative plot against time, with both axes on a logarithmic scale, shows a specific fingerprint associated to geological features such as layering, permeability, faults, fractures and channels. This paper will be of interest to engineers, geoscientists and asset managers who need a quick evaluation workflow that integrates well and reservoir data to deliver consistent and robust assessments. The ability to complete reliable fast track well test analysis has a direct impact on reduction of cost and deferred production for operators and joint venture partners.

BED 2 is a brown gas field located in the western desert, Egypt and commenced production 1982. The field has multiple reservoirs varying between carbonates, clean sand stone and shaly sand stone. Baharyia formation is the main producing reservoir in the field. In the latest years of the field life, an unrealistic recovery factor was reached making the volume of the recovered gas exceeds the maximum volume that could be recovered from this reservoir. Hence, a new further investigation and review for the previously calculated GIIP was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation subsequently a new unconventional petrophysical evaluation approach was performed. The first step in the petrophysical evaluation was to use the core data to separate the rock into different rock types "hydraulic zones" by calculating the reservoir quality index (RQI) and the flow zone indicator (FZI). After that, an electro-facies model was created using the electric logs for the model input and the hydraulic zones derived from the core data as the model learning. The resulted model matched the core data in all the four cored wells and hence it was applied to the un-cored ones. After that, the created rock typing model was used to deduce the cut-off criteria per each rock unit which resulted a huge difference from the previously calculated cut-offs and hence the NTG ratio is doubled as three types of net sand were added to the petrophysical evaluation. The first type is a very silty highly laminated sand-shale reservoir while the second one was clean sand reservoir. Conventional saturation calculation methods showed no match between the calculated volumes and production and hence different unconventional shaly sand analysis was used in calculating the saturation for the two different types of sands. The new petrophysical evaluation resulted in doubling the volumes in Baharyia reservoir and so a perforation campaign was performed to confirm the new volumetric calculations, which showed a good match with the model results. Hence, a new well was drilled targeting the low quality sand and found them with high pressure almost near virgin pressure.

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.

Digital Oilfields worldwide have accomplished many value added benefits. This paper discusses the benefits realized after implementing DOF technology in Greater Burgan Field of Kuwait. It describes how oil production is being optimized and sustained consistently. It highlights the cost savings achieved and reduction in production losses based on numerous improvements in work processes. Inevitably the ease in production management has led KOC towards further expansion. Burgan DOF technology comprises of digital instruments and infrastructure installed on wells and production facility. Well data such as pressures, temperature, water cut, flowing status and choke size is transmitted in real time to the field operations center for continuous monitoring along with key facility data. The intelligent operations system at the main collaboration center has automated workflows and smart alarm managers to instantly detect and calculate losses from wells or facility issues. Engineers can quickly analyze and make decisions for swift remedial actions using intelligent dashboards providing options for production increase from wells with extra potential. Significant tangible and intangible DOF benefits are seen from the continuous efficient asset production management. Oil production is being sustained at target with minimum downtime due to highly advanced monitoring. Customized dashboards and intelligent alarms help in improved diagnostics such as changes in water cut, sudden stoppage of well flow, scaling and slugging indication in wells due to pressure fluctuations from header trips or breaching of facility constraints. Production optimization scenarios are run daily calculating facility and well potential. Smart automated workflows integrating real time data with well and network models calculate opportunities for restoring or adding production quickly through the recommended wellhead choke or facility header changes. Burgan DOF has made troubleshooting easy, enabled quick and effective decisions and facilitated implementation of corrective actions much faster. It has provided KOC substantial cost savings with respect to BOPD restored and great reduction in non-productive time. In 2015-2016 three million dollars worth of cost saving was realized through restoration of 60 MBOPD by digital monitoring alone. Production optimization workflows provided an additional increase of 9 MBOPD. DOF technology has reduced frequency of well site visits and improved HSE measures due to presence of H2S detectors and remote controlled smart chokes. State-of-the-art collaboration center provides a highly effective collaborative work environment between the stakeholders Production Operations, Field Development and Well Surveillance enabling seamless communication for quick actions. DOF technology benefits are now well recognized by KOC leadership with concerted efforts ongoing to expand it all over the Greater Burgan field while North Kuwait and West Kuwait fields are also keenly engaged in planning switching to DOF with some pilots already completed.

To compliment the vision of His Highness Sheikh Sabah AL-Ahmad AL-Sabah to cover 15% of Kuwait's peak load with renewable energy by 2030, the Kuwait Petroleum Corporation (KPC) Strategic Directions 2030 encouraged the perusal of alternative and renewable energy sources and encourage conservation efforts. KPC established the Solar Energy Technology Utilization Team (SETUT). The objective of the team was to identify improvement opportunities relevant to solar energy technologies within Kuwait's oil sector, and to enable KPC and its subsidiaries (K-Companies) to play a more active role in energy saving by developing an effective action plan for utilizing solar energy technologies in K-Companies' facilities. Our initiative in Kuwait Oil Company (KOC) is to support the SETUT and K-Companies in their role and responsibilities to review the energy consumption and the recovered solar energy production from renewable energy projects, and to track the progress of their projects to be proactive on making decisions to achieve 15% of the total energy needs from renewable energy sources by 2030. This paper explores the contents of design and implementation of a dashboard initiative to support on reporting the renewable energy information such as energy consumptions vs. solar energy productions, and to track related projects progress through a milestone view. Now, Stakeholders of KPC can see all the actual & planned energy consumption and production, and can track solar energy projects progress of its own and its subsidiaries, where each stakeholder of a subsidiary can see only their own one. The dashboard is not limited to only solar energy projects, however, it can be fed with other projects data such as Green Building that has good impact on the environment, and it's ready to include any organization in Kuwait who contributes in renewable energy production to cover 15% of Kuwait peak load by 2030.

Most drilling-related incidents are caused by unstable boreholes, whether they are caused by lost circulation, packoff, or stuck BHA and/or casing. One of the main objectives of this study was reduction in drilling incidents and associated Non Productive time (NPT) while drilling wells in a particular area of Kuwait, where often extremely challenging environments were faced due to wellbore instability arising from tectonic stresses, associated faults, fractures, complex structures, and anomalous pore pressure. Additional challenges were presented by a complicated and highly deviated well design, where planes of weakness of the formation being drilled and their relative angle with respect to the well path become crucial factors in assessing stability of the borehole. Multiple failure mechanisms such as stress induced wellbore instability, invasion of drilling fluids into weak bedding / micro-fractures and osmotic sensitivity, were found to be the root cause of wellbore instability across reactive shale formations especially during drilling of highly deviated wells. In lie of these challenges, a comprehensive study was conducted to overcome the wellbore stability issues and investigate feasibility of drilling Ahmadi wells of Kuwait at high deviation. Correct mud weight (MW) prediction was one key factor during the drilling stage to keep the wellbore stable and deliver good borehole geometry ( Figure 1 ). The key objectives of the study were to define a safe MW program for the vertical and deviated sections of the planned well by conducting a wellbore stability study and to determine a real-time strategy to mitigate and-or manage wellbore instabiity problems as they arise. The scope of work included root cause analysis of drilling events, development of mechanical earth models (MEM) for offset wells, integrating sections of the MEM from the offsets to the planned well trajectory, and a safe MW program for planned well. The paper describes the process of optimizing the drilling practices based on geomechanical outputs, to overcome serious drilling hazards and application of real time geomechanical monitoring for successful drilling. This application promises to open the prospect of drilling similar wells without complications and reduce NPT in Kuwait.