Risk management has become of the utmost importance in the industrial world as it provides a common ground between opportunities and risks by addressing project uncertainties. In addition, inadequate risk quantification and management have a significant impact on the decision-making outcome and the success of the project. The aim of this research is to review existing literature on risk management, evaluate and rank selected resource-related risks, and propose a framework for the Kazakh oil and gas industry. Traditional risk assessment considers risks from two perspectives: the probability of occurrence and possible consequences of a risk event. These two indicators are further multiplied to estimate the risk index. This research followed the same method, but took into account the preliminary qualitative step of correctly evaluating likelihood and effect of risks. We designed a questionnaire of 15 factors, divided into equipment, labor, materials and exogenous categories. The survey was then distributed to project engineers and management professionals working in the local oil and gas industry. Price fluctuations, delays in delivery of materials, change orders, slow mobilization of equipment and its failures are identified as the most serious risks. These factors are also indicated the greatest in separate probability and impact rankings. Moreover, research findings demonstrate that the likelihood of occurrence of incompetent labor and equipment shortage is closely correlated with their possible consequences at statistically significant level using the Pearson test. Change orders and price volatility have once confirmed their importance. Finally, respondents described the amount of contingency as an indicator of a risk mitigation strategy. The suggested framework is practical for the industry and increases the chances of success of oil and gas projects in Kazakhstan and the entire region. Complex projects have a high level of technological, organizational, and informational challenges and uncertainties and are heavily resource-dependent. The combination of experts, decision-makers, and stakeholders’ judgments and statistical interpretation tools provides additional insights into the nature of risks. This study sheds light on such an important topic and improves current risk management practices.

In this paper authors share an experience of one of many ways to foster professional development culture among young engineers through organization of an internal competitions. The competition was held among reservoir engineers working in different locations across the world with a purpose to accelerate and bring to a whole new level their knowledge about one of company flagship software products as well as to use it to solve tough real world industry challenges via application of latest technology and domain knowledge. The competition was presented in a form of field optimization challenge using new high-fidelity reservoir simulator to give opportunity for everyone interested to learn and uncover simulator's broad and rich functionality. The challenge consisted of two optimization tasks targeting 1) recovery factor and 2) net present value (NPV). There were some field development constraints, such as drilling budget, availability of rig resources, surface facility capability, economic considerations – capital and operating expenditure. The model provided for this challenge represented a synthetic carbonate reservoir that has geological and petrophysical properties inspired by a real carbonate outcrop. The duration of the challenge was one month. During this period participants tested different field development plan (FDP) scenarios and at the end submitted their solutions. The engagement level among young engineers and creative solutions presented are indicative of a success of this initiative. The competition not only allowed to apply their domain knowledge to tackle real field challenges but also propelled forward their knowledge on advanced features of the simulator. Rich capabilities of the simulator allowed to implement complex operating logic to manage an asset along with getting hands-on experience designing and optimizing latest technologies such as intelligent completions. On top of that engineers learned to approach a problem from operator's point of view by optimizing capital and operating expenditure – finding a best spot for infill drilling, estimating optimal volume of fluid injection for pressure maintenance, dealing with water breakthrough in production wells and so on. The solutions were evaluated by an organizing committee in each category and winners received special awards. One of the authors of this paper had a privilege to be awarded the highest prize in "NPV optimization task". Authors will share one many proven effective methods to develop young engineers within a company through engagement and interest to solve industry problems. Also, the paper will provide case studies from the challenge that may spark an interest in industry professionals in reservoir engineering domain along with some differentiating features of new high-fidelity reservoir simulator used in this competition.

Integrated production data management system (PDMS) solution is presented that incorporates three remote locations of the company's different departments (Field Operation, Engineering and Economics) into a single working environment. Automated workflows implemented on the basis of PDMS aimed to improve speed and efficiency of engineering analysis and economic planning. PetroKazakhstan Kumkol Resources JSC operates a wellstock consisting of more than fifteen hundred wells. Operational data is loaded into a system on a daily basis at a central office on the field site. At this stage data is quality checked and used for production monitoring. All information is automatically synchronized to the office in Kyzylorda city, where production back allocation is performed. Every month regulatory reports are generated from the system. Decline curve analysis forecasts at well level are frequently applied for daily routine economical assessment of well intervention and surface construction operations. Moreover, saved forecasts are also automatically available for budgeting purposes in Almaty office. As a result of integrated PDMS solution, PKKR JSC engineers and economists get easy and automated access to raw operational data as well as results of allocated production and forecasting by the decline curve analysis (DCA). Automated workflows for back allocation, regulatory report generation and forecast result data sharing made different departments closer and decision making more efficient. Overall, data travel distance of about 1500 km. Shared workspace with standard analytical templates (plots, reports, maps, forecasts) allowed engineers to promote best practices across organization, align reservoir surveillance and monitoring approach in a common standardized way. PDMS allows engineers, previously overloaded with manual data handling and reporting, to have more time to solve reservoir and production engineering problems. Meanwhile, the economists gain direct and automated access for DCA forecasts, performed by reservoir engineers, not only at field, but also at well level. This helps prioritize each well's economic potential and rank accordingly, which is critical in budget planning. The novelty of integrated PDMS solution is that it brings a new level of integration of different departments into synergy. Teamwork spread beyond engineering, operations and geology, adding economists into the team to address today's operational challenges.

Kashagan oil field has been under production since September 2016. The produced oil is associated with considerable amounts of sour gas that must be processed or disposed of while minimizing flaring. This paper will focus on the methodology for field development planning and production forecasting, incorporating gas reinjection and sulphur management with the objective of optimizing production, subject to operational constraints and bottlenecks at surface facilities. The field development plan includes reinjection of associated gas into the reservoir to increase oil production capacity at the surface and provide reservoir pressure support, while satisfying government regulations that do not allow continuous gas flaring. This requires analysis of H 2 S concentration and sulphur production, since the ultimate surface constraint at Kashagan field is sulphur processing capacity. We describe reservoir modeling workflows for oil production optimization with integrated logic for gas balancing. The impact of sulphur management on oil production is studied under different scenarios using a high resolution, fully compositional reservoir model. The procedures for management of the production facilities have been translated into reservoir simulation logic, including product streaming from facilities and processing constraints. This includes gas accounting and prioritization of gas with low H 2 S content to be processed at the sulphur recovery unit. The remaining gas with higher H 2 S content is sent back to the injection stream. Workflows have been developed using tailored scripting with user-friendly input of facilities constraints using spreadsheets to enable the model to be maintained in a ‘live’ state. Automatic allocation methods are used for prediction forecasting that penalize higher gas production wells but still provide incremental oil production. Development of a product streaming model allows for reporting of production of liquefied petroleum gas (LPG), dew-pointed gas, etc., in addition to the standard simulation results. The comprehensive guidelines provided in this paper can aid reservoir modeling and surveillance for a field through accurate analysis of actual operational constraints and bottlenecks as part of the planning process. The described gas and sulphur management logic provide pivotal information to enable the reservoir engineering and production teams to meet the challenges of development planning for a sour reservoir.

This paper describes the application of Integrated Production System Modelling (IPSM) at Kashagan field. The IPSM is used for short-term, mid-term production plan and business plan forecasting, opportunity identification/validation and production optimization. The IPSM modeling strategy is to build fit-for-purpose model which produces accurate results with minimal running time. IPSM enables integration of surface network (GAP) and reservoir simulator through Resolve by Petroleum Experts. This in turn helps to replicate actual field performance by incorporating field management logic (script) and modeling relevant system constraints. While there are many constraints governing the maximum production in Kashagan field, they can be summarized into two main constraints: injection capacity and sulphur processing capacity. Modeling of the latter is essential to consider the impact of composition change over time. As a result of continuous improvement of existing model and close collaboration with multiple teams, IPSM model has proven its prediction capability with forecast accuracy of 99%. Current IPSM model is able to produce results for various streams: oil & gas production, gas injection, Sulphur throughput, etc. Additionally, IPSM demonstrated its importance in identification and evaluation of various production opportunities / threats as well as its need in influencing management decisions. After calibration of pipeline network to match actual data, a substantial potential opportunity of optimizing existing wells capacity was revealed. This is vital not only for short-term production optimization needs but also for long-term predictions. This paper presents several case studies and examples of application and value of Integrated Production System Model in the field. Learnings during implementation of a given feature are also described. Provided examples can be useful for other engineers practicing Integrated Production Model suite.

The Bulak field is a unique oil field located in the South-Turgai basin. It consists of heterogeneous carbonates. Throughout the field, the reservoirs vary from highly fractured clean limestones with strong aquifer to very tight limy claystone with low amount of bed-bound fractures and no water production. Active infill drilling followed after the exploration stage revealed uncertainties related to the main issues of development, i.e., location of new wells, their trajectory, EOR techniques and most importantly, waterflooding. A comprehensive study was conducted based on all the petrophysical, seismic, geological, and reservoir engineering data. As a result, 3D geological and dynamic models were built. During the analysis, special focus was on geological structure and petrophysical characteristics as well as pressure transient analysis due to drastic changes in reservoir properties within small distances. In addition, the production history and the main stimulation, and EOR measurements, especially fracturing, acidizing and nitrogen huff ‘n’ puff results, were taken into account. Eventually, the waterflooding was simulated to identify its benefits and possible field application. Based on comprehensive study, the field is divided into several zones. The main criteria for dividing became a lithology that is represented by weathered crust, pure limestones, shaly limestones, limy claystones, and bioliths. Each part requires a different approach in development. If the north part is highly fractured and consists of limestones, water shut off is required due to active aquifer, middle part pressure support and the south part horizontal drilling or sidetracking with multistage high-tonnage fracturing. As a result, waterflooding was decided to be implemented in the part of the field characterized by ultralow permeability formation. Thus, recently, four producers were converted to water injection along with the fact that the injection is performed using low-salinity water. Surprisingly, injectors' rates are high enough, current voidage replacement ratio is sufficient and the results are unexpected. The reservoir is very complex where the lithology is drastically distributed within a small area. However, most of the territory is represented by very tight formation. Eventually, after several years of fields operation, many aspects became clear after the research work and development strategy was updated. So, the company is ready to develop such an unconventional reservoir that is one of the few fields in Kazakhstan.

Multiple methodologies and grid geometries were applied to model the production performance and uncertainties in the planning and execution of a pilot horizontal well with multiple hydraulic fractures. The well is located in a tight carbonate formation and the fracture will be induced hydraulically with acid. A methodology was established to scale the observations of the single well model to a full field scale. This, when calibrated against actual performance from the pilot well, will enable improvements in the planning the development of the target reservoir at full field scale. The methodologies described in this paper consist of fine grid models to explicitly represent the fractures, a method to calibrate and represent the production performance on a coarse grid full field model. In the fine grid model, the grid was geometric refined to fracture aperture grid size to capture the physics and flow behavior induced by the acid-fracs. Fracture plane conductivity is based on laboratory measurement of acid-frac experiments. The fine scale model was also used in sensitivity analysis to optimize the pilot well design such as number of fractures and desired fracture height growth, identify risk of water production and help formulate of mitigation strategies. To enable modeling at full field scale – which is impractical with fine grid models – a novel methodology was established to calibrate a coarse grid field scale model to consistently reproduce the fine grid model behavior. This enables early planning of full field development should the performance of the pilot well support the application of multi acid-frac horizontal well as the preferred technology.

Reserve/Resource estimation plays a crucial role in a feasible oil and gas business. Tendency of producing more from unconventional reservoirs and their relatively new as well as different structure brought on a learning curve for the applications of new reservoir evaluation methods. This study clearly desribes all reserve and resource evaluation techniques, the latest developments in this area by providing a single-source up-to-date reference for reserves evaluation in unconventionals. An extensive review of literature has been applied to describe all available reserve evaluation techniques and their utilization, applicability and robustness, the history of using these techniques, types of technologies which applied in conventional reservoirs and transferred to unconventionals, and their incremental benefits of usage.This paper includes a real worldwide case studies which are illustrated with applications, and briefly describes the challenges, drawbacks, also pros and cons case by case. In the end, each case leads to conclusions on the criteria of application of methods as they related to SPE, SEC and PRMS. In this study, "reserve and resource estimation" of unconventional reservoirs is investigated. The techniques are described by giving their methodology, as well as identifying the crucial parameters and the key factors of the applying procedure for the estimations. For instance, the main key factor of reserves evaluation is consistency and abiding by the rules outlined by SEC, PRMS and other bodies in terms of technical and economic aspects. Currently, some studies includes the certain examples of reserve evaluation methods in conventional reservoirs, and limited number of works in unconventionals. However, there is no study which is not only outlines the key elements in one study, but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications. This study will close the gap and become a reference study in unconventional oil industry.

Development of the Kashagan field is very complicated and encounters many challenges, such as a harsh offshore environment with an ice season, highly pressurized wells and a high H 2 S concentration (sour). All these challenges were known during the field construction phase, but after one year of production, another unforeseen challenge emerged– severe downhole scaling in certain oil producers, flowing at very low water cuts (<0.5% water). Scaling is a widespread and well-known phenomenon in many, often mature fields around the world, but it was not expected to occur in Kashagan in the early stage of field life. Well scaling developed very fast, leading to almost 50% productivity reduction on several wells in a few weeks time. Wellbore scaling put Kashagan production plans at risk, so it was critical to remediate the affected wells as soon as possible. A multi-disciplinary team started work to address the issue. For most "brown" fields, remediation of wells affected by scaling is a routine job. In the case of Kashagan, which had just started production, downhole scaling was a big challenge for various reasons. Firstly, when rapid productivity decline was observed on some wells, it was not clear what caused the impairment, and a lot of investigative work was done to identify the nature of impairment and root cause (mechanism) behind it. Secondly, scaling badly affected D-island wells, where SIMOPS well intervention capability is highly restricted. D-island is a hub for offshore processing and gas reinjection facilities, located just few hundred meters away from wells, and any well intervention requires the creation of a "yellow zone" and causes significant production deferment. Thirdly, it was clear from the beginning that remediation is a temporary measure, and that it was important to progress from "firefighting" mode to impairment prevention mode, for all wells. Despite all complexities of the task all affected wells were successfully brought back to production and, after various successful anti-scale treatments, fine-tuning of the scaling prevention process is currently ongoing. Due to the scaling, multiple processes had to be improved, such as metering, wells testing, wells surveillance and well interventions. In the design phase of the project, a well intervention was considered as something extraordinary, and expected to happen rarely, primarily for well integrity issues, not for scaling issues. Well intervention operations became a more routine operations and have started to play a critical role in the integrated activity planning process. This paper describes how Kashagan wells were affected by wellbore impairment and what actions were made to remediate wells and to return wells to its original productivity.

As oil price is getting more volatile these days, O&G operators had to think outside the box and be innovative in optimizing well design that can contribute to reduction in overall well cost. Conductor casing or drive pipe design, is an aspect that was put into spotlist to offer significant cost savings. Conductor casing string typically uses same pipe size and thickness from surface to the planned setting depth. The design is based on estimated safe working structural load that it will encounter post-installation. One of the design load is from the vortex induced vibration (VIV), an important source of fatigue damage on conductor casing and it will directly affect conductor design ie. Grade, size and wall thickness. As VIV only occurs across pipes in water, the conductor casing joints inside the soil/below mudline are not affected by VIV fatigue damage. Hence, a tapered conductor design was introduced, by combining 2 different conductor wall thickness above and below mudline, based on the VIV exposures across the string. This paper discusses on the challenges from design, planning to execution stage, in installing the tapered conductor to the setting depths seamlessly, without compromising HSE and well structure, by adopting fit-for-purpose design that contributes to effective cost optimization

The process of creating, maturing and ultimately submitting a field development plan for a given resource is often complex, time consuming, and inefficient; perhaps inextricably linked to its multi-disciplinary nature. The workflow(s) traditionally used in today's industry are domain-centric, involve many discrete software programs resulting in a linear process which limits optimization and prevents cross-domain collaboration. The paper describes an innovative field development planning (FDP) methodology, utilizing deep domain expertise supported by leading-edge software technology and illustrates the benefits through a study case in the Caspian Sea. Although well-established software tools exist for isolated parts of field layout, no existing platform integrates the equipment selection, systems knowledge, field layout, economics, and software simulations required for the entire planning process from feasibility studies to detail design and optimization. The paper describes an innovative field development planning methodology that combines lean project execution and uses the industry's first cloud-based collaborative subsea FDP software environment, providing efficiency and optimization. This is achieved by combining full-field economics with petroleum engineering disciplines, subsea systems engineering, subsea technology selection and installation knowledge spanning the entire planning process and visualized through a single working environment. This paper demonstrates how the core value of multi-discipline domain knowledge can be truly integrated through the use of collaborative workflows based upon cloud-based platforms and how it transforms concept development and selection in the upstream industry. In the early stages of exploitation planning, from the feasibility and concept selection phases, operators plan for the development of a field that will produce for 20 years or more. It is at this early phase that key Tier 1 level decisions are taken often with limited reservoir information and a significant range of uncertainty. The short duration of these initial stages inevitable means that operators rarely have the time or resources necessary to evaluate all possible development scenarios, and decisions are taken with less conviction or assurance than is desirable. As a result of this sub-optimal way of working, exploration and production companies are constantly seeking tools, methods and processes to enable the multi-scenario evaluation and option screening that will improve decision quality in field development planning. This paper demonstrates this novel approach through a practical example of such an FDP study, focusing on a case study relevant to the Caspian region. The discussion seeks to illustrate how the single working environment improves collaboration between disciplines whilst identifying cost savings and opportunity gains of the recommended development scenario.

Tengizchevroil (TCO) is the largest operator in Kazakhstan developing two of the world’s deepest supergiant oilfields - Tengiz and Korolev. The concept of an Integrated Operations Center (IOC) has been developed and implemented over the last few years in TCO. The TCO IOC approach has been established in both Plants and Field Operations to perform rigorous planning of short and long-term activities, improve communication between operational teams (Field Operations, Plant Operations, Reservoir Management Group, Process Engineering Team, Projects Team, etc.) and increase production efficiency at the Field and Plant level. Two key objectives of the IOC are to utilize an Integrated Asset Management approach to ensure field deliverability is available to maintain plant production demands throughout the year, as well as to utilize planned/unplanned facility downtime to execute field facility maintenance and project scope, reservoir surveillance jobs, etc. The IOC collaborative environment allowed TCO to improve production efficiency in the field and at the Plant by establishing a clear communication bridge between multi-discipline groups, and implementing a "conflict resolution" process, which enabled all relevant groups to perform integrated planning. The overall IOC process has added more than 15,000 bbls of daily production. One of the key components to the success of the Integrated Asset Management approach was to embed a production engineer in the IOC to ensure field work scope decisions and scheduling are based on short and long-term production deliverability. This paper outlines how a real-time system can be used for production planning optimization, resource allocation and integrated plan development. The paper includes a discussion of how the Integrated Asset Management approach can be utilized in an operation center to address some of the challenges associated with production planning in field operations.

This paper presents the recent developments that have been achieved to improve the Karachaganak Integrated Asset Model (IAM). In 2014, SPE-172330 showed a step change in the application of integrated modelling techniques to this complex field and demonstrated the significant value of integration compared to standalone techniques. The complexity of modelling and integration is driven by more than 120 operating wells (production and injection), a complex gathering system, multiple processing facilities and multiple export lines, combined with gas reinjection for reservoir pressure support. To correctly capture real operations, the model requires layers of constraints at well, facility and export levels and an appropriate line-up of wells to maximise field oil and gas production. The model has been used to evaluate multiple field development projects with intensive capital investment worth several billions of US dollars. Hence, it is critical to ensure that the model is robust and replicates the reality. The latest improvements presented in this paper include a description of a more enhanced field optimisation approach that fulfills oil and gas export as well as gas reinjection targets whilst respecting all of the field constraints. Optimising such a complex problem is a challenging task considering the number of variables and constraints in the system. Production well ranking for line-up selection has also been improved. Rather than following a single approach of well prioritisation, for example by well Gas/Oil ratio to maximise liquid production, in the new methodology wells are smartly picked to fulfill all export and gas injection targets. Another improvement in the model was converting the optimisation logic, which was previously based on scripts, into open and transparent workflows using Visual Workflows in Resolve (application for connecting and running integrated models). This approach made it possible for Engineers to read, modify and extend the logic without having programming skills, bringing flexibility and sustainability into the model. Several case studies of actual project evaluations using the improved Integrated Asset Model will also be discussed. These studies highlight the key results, the importance of the implemented improvements for decision-making and how these affect the bottom line of projects.

Modernization of the regulatory framework of the Republic of Kazakhstan (RoK) will complement the "100 Concrete Steps" national initiative of President Nazarbayev. Planned reforms aim to increase the transparency and predictability of the subsoil use sector by implementing an international system of reporting standards. The Society of Petroleum Engineer's Petroleum Resource Management System (SPE-PRMS-2007) is the most likely choice for the hydrocarbon sector, as the guidelines can be altered to meet the needs of RoK to increase the contribution of petroleum production to drive economic growth, improve governance, and attract more investment, along with best available practices and technologies, in RoK. A comparative analysis of the leading petroleum resource reporting systems used by governments and stock markets around the world concurred that a tailored SPE-PRMS-2007, which was named KAZ-PRMS, was the most appropriate system for the needs of RoK. Discussions were then held with a RoK Working Group, which was comprised of government bodies, technical institutes and operators, to address their concerns and to get their ‘buy-in’ to create a road map for the development and implementation of the new Code for Reporting Hydrocarbon Resources (Code) as required by international SPE-PRMS standards. The initial concerns about migrating to a new reporting system of some of the Working Group were overcome via open and lively discussions, by workshops and through focused training sessions. The various parties concurred that migrating to KAZ-PRMS could be a valid alternative to the existing RoK resource reporting system from the Soviet era, which is disliked by the international investor community. There remained some concern over the proposed speed of change presented in the road map, but there was consensus for the need for change. The administrative, technical and cultural challenges facing the RoK, which intends to radically overhaul its Soviet-era regulatory system and its petroleum resource reporting structure, whilst remaining legally compliant, are described in detail.

Pressure losses in the surface network can have a critical impact on well productivity. Therefore, for field development planning, it is highly advantageous for the simulation model to include the surface facilities as well as the reservoir. The objective of this study is to outline the advantages of modeling reservoir-to-surface coupling over conventional standalone simulation. This paper presents a case study of creating an integrated model of a giant oil field with a compositional surface gathering system. The reservoir model is controlled by complex field management logic including gas balance. The reservoir wells are balanced with the surface network by setting inflow performance relationships (IPRs) as the boundary conditions. The network is then solved and returns operating point pressure as a varying tubinghead pressure (THP) limit for the reservoir well. After the minimum THPs have been established, the guide rate balancing allocates production by respecting the THP limits at which wells can flow. The results show that an integrated reservoir-to-surface coupling gives significantly different but more realistic production allocation profiles at the group and well levels than a separate standalone simulation model. The oil production plateau rate drops prematurely as surface-network-constrained guide rate balancing results in different production allocation between producing wells. In fact, updated allocation results in an increase in gas-oil ratio for some of the groups and consequently leads to early gas breakthrough for some of the wells. Increase of stability in results and speed were achieved by selecting the appropriate reservoir-to-surface-network balancing frequency and leveraging the power of multicore hardware. The sequence of network and guide rate balancing can over-constrain some of the high-capacity groups by a higher THP limit. To avoid this, a nested approach is presented that includes an additional network balancing step that is solved by IPRs based on guide rate balancing, which allows reducing the THP limit and prolongs the plateau rate. Based on this field example, integrated modeling has proved to bring value by providing more accurate profiles and debottlenecking of surface facilities.

As part of the LUKOIL smart-field project, the company develops and implements integrated modeling solutions in all its assets. LUKOIL-West Siberia, a subsidiary company that is LUKOIL's leading hydrocarbon producer, has chosen two pilot assets in Yamal to implement such technology solutions. This paper describes the creation and implementation of two integrated models, as well as model of gas transportation system from a group of fields located in the Yamal and the Krasnoyarsk region. Each integrated model includes the following components: reservoir – well – gathering system – processing. The results of the project implementation allowed to increase production performance and economic viability of the operator company and provided technology that enabled to forecast production rates with high accuracy.

The Pierce Field in the UK Central North Sea has production potential significantly beyond the originally anticipated life. A Life Extension project was initiated to develop a scope of work to refurbish and upgrade the facilities, suitable for the revised field life. The initial plan was to perform a ‘full reset’ of the facilities to extend their operating life for a further 15 years, but this resulted in a very long production outage (14 months) with an intense period of capital spend in the short term. With the low oil price environment emerging at the same time, there was a need to identify an alternative approach which would significantly improve the field cashflow by phasing the Life Extension work. The revised approach was to develop a solution which had a more equitable balance of risk and value against cost, with production uptime a key value driver. Fundamental to this was building an understanding of the existing condition of the facilities and then developing a risk-based view of how they were likely to perform for the extended operational period. Focussing on the major risks and assessing them individually, ‘Decision-based’ roadmaps were then developed to plan the technical work required to enable decisions on mitigations to be made. A ‘Competitive Scoping’ mindset was used to ensure fit-for-purpose solutions were tailored to the specific risks. Starting from a ‘do-nothing’ perspective as the base-case, the incremental value of the mitigations was shown and compared to the level of risk reduction they brought. This then allowed decisions to be made on the optimum mitigation solution. In addition to the technical assessment of the individual risks, the execution strategy was also developed and concluded that a phased approach was achievable and would significantly improve cashflow from the asset. The result was a Life Extension ‘Programme’ rather than a single ‘Project’, where short, medium and long-term Life Extension scopes are scheduled according to their necessity. Each Life Extension scope will be managed as an individual sub-project and only executed ‘when required’. The revised strategy avoided an extended production outage in the short term, reduced total cost by circa 50%, and phased the spend over approximately 10 years.

The digital oilfield technology is typically associated with high level of field automation and instrumentation, as well as advanced petroleum engineering modelling. This paper discusses the application of digital oilfield to large brown fields based on real, but anonymous cases, where the level of instrumentation is low, production models might not be available, and the local expertise might be limited. In such situation, the principles of digital oilfield need to be adapted. This paper presents a staged implementation methodology, where the benefits and costs can be evaluated at every step of the project, allowing to build a system with the right amount of functionality and complexity. The first step focuses on improving data quality, even if the data is captured manually, through automated quality checks and raising awareness during the data capture process. The second step focuses on automating routine tasks, such as reporting, leading to efficiency improvement, but also increased accuracy and traceability of the reported figures. The third step focuses on developing a production monitoring platform, allowing to perform exception-based surveillance, particularly important for large fields, as well as providing a single point of access for different disciplines, hence acting as a collaborative environment. At last, the model-based more complex workflows are discussed, such as virtual metering, production optimization and short-term production forecasting. The main conclusion of this paper is that the Digital Oilfield can deliver value for brown fields, even if they are close to their life end. The relatively low cost of these solutions, and the immediate benefits they can provide makes it meaningful, even in a short-term perspective. A staged implementation lowers both the project risks and the required initial investment, while easing the adoption process by the users. The main differences with application to green fields is an increased focus on data quality improvement, and a lower focus on models and complex engineering workflows. The surveillance platform should also focus more intensively on exception based surveillance, allowing to pre-process large amounts of data, rather than providing extremely fine detail.

Reservoir to surface Integrated Asset Modeling (IAM) is a cross-functional simulation, monitoring and decision tool. It captures the complex interactions all along the production / injection system of an oil or gas development. It is a powerful tool to maximize the value of an asset from the development phase to the end of the production period. This paper describes the successful work achieved for unlocking the challenging development of Absheron deep offshore gas condensate field through an integrated asset work and modeling. The IAM has been the result of a multi-disciplinary and collaborative work where each disciplines, namely reservoir, well, network and surface process engineering, provided their inputs. A fully compositional fluid modeling was required to capture the challenges of such a long gas export production line with stringent thermal requirements due to the paraffinic content of the produced condensate, impacting at first order both plateau duration and economics. During all the pre-FEED engineering, attention was given to ensure consistency and synchronization between the IAM and the progress of the design work performed in parallel by each disciplines. Many sensitivity calculations on development parameters have been performed to quantify the impact of the geosciences uncertainties and other design parameters to define the optimum combination of production facility design, operating philosophy and monitoring strategy. The first phase has been a screening with different production network design parameters associated to the base case reservoir model, namely the pipeline insulation and the arrival pressure. The second phase has been to test the robustness of the proposed design towards reservoir base case uncertain parameters such as the well overall exchange coefficient, reservoir temperature, water break-through, fluid modeling and gas-water contact. The third phase has been to test the robustness of the proposed design towards low and high reservoir cases. All along these phases, many iterations and collaborative work between reservoir, well, network and process engineers occurred, all centered around the IAM offering the possibility to evaluate the production profiles associated to different designs assumptions while the different disciplines eventually performed more advanced "stand-alone" studies to further assess specific technical points. The work performed for Absheron development highlights the benefits of integrated asset work and modeling to enable an economic development scheme robust towards uncertainties (petrophysical, structural modeling, water break-through…) and therefore not over designed

Overview North Caspian Operating Company N.V. (NCOC) is the operator of activities under the NCSPSA (North Caspian Sea Production Sharing Agreement) formed to explore and produce hydrocarbon within the 5,600 square kilometer including the giant Kashagan field, one of the largest petroleum developments in the world. The Kashagan field is located in the Kazakhstan sector of the Caspian Sea and extends over a surface area of approximately 75 kilometers by 45 kilometers, in stages with the first element designed to produce around 450,000 barrels/day. The water depth in the development area is less than 4m and is ice bound during the winter season. The development of Kashagan, in the harsh offshore environment of the northern part of the Caspian Sea, represents a unique combination of technical and supply chain complexity. The combined safety, engineering, logistical and environmental challenges make it one of the largest and most complex industrial projects currently being developed anywhere in the world. The Kashagan Field Development Project is an extremely complex development in respect to the technical issues associated with developing a high pressure, sour hydrocarbon reservoir in a hostile environment. Beyond oil and gas, NCOC believes that NCSPSA activities can and will bring many benefits and opportunities to Kazakhstan. The Kashagan Laboratory Services have numerous responsibilities for the analysis of the complete range of fluids and chemical associated with the production operations. These include reservoir fluids, plant process fluids, plant products and by-products and waste. The laboratory also assess emissions to the environment by production and process streams and monitor a wide range of environmental substances which are considered relevant to Kashagan operations. Other functions include the support of equipment condition monitoring with the analysis of lubrication oils, grease and another condition related materials and fluids. Onshore Chemical Laboratory is central repository for all laboratory activities. An onshore production laboratory provided in the Eskene West area (Samal camp) to undertake all required complex analytical testing. It is envisaged that the onshore laboratory shall additionally carry out all future Kashagan development testing and analysis. A second production laboratory provided on D island where utilized very basic laboratory analysis. It is incumbent upon any prudent operator to measure the chemical composition of the products and by-products that it produces. Measurements collated are used to certify to regulatory authorities and Joint Venture partners that product chemical content is within agreed specification parameters. To achieve the very high specifications and standards of measurement required a Production Laboratory containing specialized and certified laboratory equipment has become a feature of most production facilities. When appropriately configured and connected to the laboratory equipment a Laboratory Information Management System LIMS software application is used to define and manage the procedures, schedules, capture, storage and reporting of data from various measurement scenarios and physical equipment within the Production Laboratory. LIMS supports the laboratory work and provides timely and accurate information to plan operators, managers and other relevant groups within company, its partners and government and regulatory bodies. LIMS system is also receiving store and report data from online plant analytical instrumentation for validation purposes.