The objective of this work was to develop the prototype unit of Advanced Production Separator (APS) for simultaneous removal of sand, out from production separator. APS unit was fabricated with size Diameter × Length: 1 × 2 m. System controlling of rotational blades impellers was installed at the bottom section of separator, to prevent sand accumulation at bottom of separator while on-service. This facility will help in preventing of sand accumulation in the separator, leading to minimize period of separator downtime during annual maintenance period, and allowing more working volume for open fluid reservoir to gas-oil phase production separator. Moreover, this will minimize working period for worker going inside the separator for sand clean-out, as a concern of working in the confine space. The optimum conditions for separation of sand and crude oil will be examined, with Computational Fluid Dynamics (CFD) model simulation to observe hydrodynamic flow, relating the experimental conditions. The effects of size of 1) Imperller shapes (model A, B, and C), and 2) Rotational speed of impellers (0, 50, 100, 150, and 200 rpm) were investigated to determine the optimal conditions for APS system. In this work, experimental test run result were compared with CFD simulation result. The optimum conditions for prototype APS unit (800 Litres capacity) is Fan C impeller shape for 5 items, and rotation speed for 150 rpm. This result shows the percentage of sand removal reaching to about 70%. The highest amount of sand in water outlet was found at this optimal condition, corresponding with the small part of sand dune at the bottom of the separator after impellers were driving sand to the outlet channel. From the test run, it was found that experimental results, and CFD simulation are consistent. CFD simulation result can be applied as a first screening to forecast sand removal pattern. This research illustrate the alternative novel solution for solving sand production accumulation problem in production separator, by instantly clear sand out while crude oil operation was on-going. In the future phase, CFD simulation will be further used as a first step for predicting result before separator scale-up. Separator will be experimented with 4-phases (oil, water, gas, and sand), and further expand for 4X of the original size to see an effect of scale-up. Aim to unlock high potential field, by reducing downtime of the separation during sand cleaning, and providing more working volume of separator after sand was removed out from self-cleaning separator.

This study presents a hybrid approach that combines data-driven and physics models for worn and sharp drilling simulation of polycrystalline diamond compact (PDC) bit designs and field learning from limited downhole drilling data, worn state measurements, formation properties, and operating environment. The physics models include a drilling response model for cutting forces, worn or rubbing elements in the bit design. Decades of pressurized drilling and cutting experiments validated these models and constrained the physical behaviour while some coefficients are open for field model learning. This hybrid approach of drilling physics with data learning extends the laboratory results to application in the field. The field learning process included selecting runs in a well for which rock properties model was built. Downhole drilling measurements, known sharp bit design, and measured wear geometry were used for verification. The models derived from this collaborative study resulted in improved worn bit drilling response understanding, and quantitative prediction models, which are foundational frameworks for drilling and economics optimization.

Maintaining zonal isolation is vital to well economics and productive life. Well integrity is becoming more challenging with the drilling of deeper, highly deviated, and horizontal wells worldwide. Oil companies are focused on to enhance the well productivity during drilling long horizontal wells in a harsh environment by achieving maximum accessible reservoir contact. These wellbore geometries incorporate additional challenges to design and deliver a dependable barrier. In this paper, a case study about cementing the longest liner across Khuff-C reservoir has been presented discussing the main challenges, engineering considerations, field implementation, results, and conclusions. The well was drilled horizontally across Khuff-C carbonates using oil-based drilling fluid. The 5-7/8-in open hole section was planned to be cemented in single stage, utilizing 8370 ft of a 4-1/2-in liner. Careful attention was paid to estimate the bottom hole circulating temperature, using the temperature modeling simulator. A 118-lbm/ft3 slurry was designed to keep the equivalent circulation density intact. Gas migration control additives were included in the slurry design to lower the slurry's transition time, in order to reduce the chances of gas migration through the cement slurry. The slurry was batch-mixed to ensure the homogeneity of the final slurry mixture. A reactive spacer was designed to improve the cement bonding from long term zonal isolation perspective. Additionally, the spacer was loaded with optimum amounts of surfactant package to serve as an aid to remove the mud and to water-wet the formation and pipe for better cement bonding. Centralizers placement plan was optimized to allow around 63% average standoff around the pipe, staying within the torque and drag (T&D) limits. The cement treatment was performed as designed and met all zonal isolation objectives. The process of cementing horizontal liners comes with unique procedures. There are several challenges associated with carrying out wellbore zonal isolation for primary cementing of horizontal liners, therefore, a unique level of attention is required during the design and execution stages. The slurry design requires careful formulation to achieve the desired specifications while ensuring its easy deployment and placement in the liner annulus. By planning in advance and following proven techniques, many of the problems associated with the running and cementing of deep and long horizontal liners can be alleviated. This paper highlights the necessary laboratory testing, field execution procedures, and treatment evaluation methods so that this technique can be a key resource for such operations in the future. The paper describes the process used to design the liner cement job and how its application was significant to the success of the job.

Drilling rate of penetration (ROP) is one of the variables that influences well delivery timing and cost. ROP is affected by many factors, including but not limited to rock strength, well profile, bottom hole assembly (BHA) design, challenging formations per section, and drill bit selection. In one of the drilling projects in the Middle East, the primary method chosen to improve well delivery is to focus on optimizing the drill bit design to improve ROP while delivering other drilling objectives. As the project progressed, the ROP plateaued in most of sections in the field. The drilling team collaborated with the drill bit engineering to launch a drill bit optimization campaign in various hole sizes ranging from 16-in to 6⅛-in. Since fixed-cutter bits are predominantly used in these sections, improvements are made to the existing drill bit designs by replacing the cutting elements with more efficient 3D polycrystalline diamond compact (PDC) cutters or 3DC. 3DC cutters have different shapes, uniquely designed to tackle different drilling challenges. Using an in-house petrophysical log analysis program, each formation drilled in this field was analyzed and drilling challenges and ROP values were compared against previous performance. This information paired with finite element analysis (FEA) for dynamic drilling simulation was used to optimize drill bit selection. This conceptual workflow was followed to avoid costly field tests and ensure that the newly designed drill bit performs flawlessly downhole. Other design elements, such as choosing bit body material, were also incorporated by converting matrix-bodied to steel-bodied, which not only improved the ROP but also reduced the cost-per-foot (CPF). Initially the bit optimization program enabled ROP improvement in the 16-in section by 36% from 53 ft/h to 73 ft/h by replacing the roller-cone bit with a matrix-bodied fixed-cutter bit. Moreover, the drilling team further improved their performance, achieving 118 ft/hr. ROP when using the steel-bodied bit. With successful deployment of 3DC cutters in Middle East, ridged diamond element was introduced in the 8½-in section and successfully improved overall ROP by 11%. In addition, the 6⅛-in section showed 25% improvement in ROP following several design iterations that utilized two different types of 3DC cutters. By the end of the drill bit optimization campaign, the operator was able to improve the drilling curve and save up to 2.5 days per well. The 3DC cutters also helped eliminate the risk of bit failure in the 8½-in section, wherein offset wells several bits were required to complete the section. With the performance mindset, new technology deployment made it faster to test new bit designs. This helped with getting early data point for analysis before being able to test in the different fields in the area.

Accurately characterizing fracture network morphology is necessary for flow simulation and fracturing evaluation. The complex natural fractures and reservoir heterogeneity in unconventional reservoirs make the induced fracture network resulting from hydraulic fracturing more difficult to describe. Existing fracture propagation simulation and fracture network inversion methods cannot accurately match actual fracture network morphology. Considering the lightning breakdown similar as fracture propagation, a new efficient approach for inversion of fracture network morphology is proposed. Based on the dielectric breakdown model (DBM) for lightning breakdown simulation and similarity principle, an induced fracture propagation algorithm integrating reservoir in-situ stress, rock mechanical parameters, and stress shadow effect is proposed. The fractal index and random function are coupled to quantitatively characterize the probability distribution of induced fracture propagation path. At the same time, a matching rate function is proposed to quantitatively evaluate the fitting between fracture network morphology and the micro seismic data. Combined with automatic history matching method, the actual fracture network morphology can be inverted with the matching rate as objective function. The proposed approach is applied to fracture network simulation of mult-fractured horizontal wells of shale oil reservoir in China, and the fracture networks from inversion fit well with the micro seismic data. A simulation of 94 fractures in the 32 section of Well X2 shows that the well propagates more obvious branch fractures. The single-wing fracture network communicates approximately 200m horizontally and approximately 10m vertically. In single fracture flow simulation, it is necessary to consider the influence of complex fracture network morphology, but when simulating fluid flow for a single well or even a reservoir, only the main fracture needs to be considered. This paper proposes an induced fracture propagation algorithm that integrates reservoir in-situ stress, rock mechanical parameters, and stress shadowing effects. This algorithm greatly improves the calculation efficiency on the premise of ensuring the accuracy of induced fracture network morphology. The approach in this paper provides a theoretical basis for flow simulation of stimulated reservoirs and optimization of fracture networks.

The application of Artificial Intelligence (AI) methods in the petroleum industry gain traction in recent years. In this paper, Deep Reinforcement Learning (RL) by pixel data is used to maximize the Net Present Value (NPV) of waterflooding by changing the water injection rate. This work is the first step towards showing that learning from pixel information offers many benefits, for example, understanding the reservoir's physics directly by measuring changes in pressure and saturation distribution without taking into consideration reservoir petrophysical property and the total amount of wells with corresponding locations. The optimization is tested on the 2D model, which is a vertical section of the SPE 10 model. It has been shown that RL is able to optimize waterflooding in a 2D compressible reservoir with the 2-phase flow (oil-water) by means of pixel data. In the first few thousands of updates, optimization remains in the baseline NPV since it takes more time to converge from raw pixel data than to use classical well production/injection rate information. The reservoir NPV increased by 15 percent as a result of optimization, where the optimum scenario results in less watercut and more stable production. Additionally, we evaluated the impact of choosing the action set for optimization and examined two cases where water injection well can change injection pressure with a step of 200 psi and 600 psi. The results show that in the second case, AI optimization is exploiting the limitation of the reservoir simulator and tries to imitate a cycled injection regime, which results in a 7% higher NPV than the first case.

After the successful pilot (18%STOOIP incremental oil, Juri et al. 2017 and utility factor of 1,76 kg polymer/bbl) of two technologies, continuous polymer injection 0.3PV followed by high frequency water-alternate-polymer 0.3PV, a series of multiple simulations cases indicated an optimal extension of 3-year cycle -0.4 to 0.6PV- factory mode development. Despite all advantages of polymer injection, few full-field expansions emerge from many challenges in integrating multiple disciplines -lab studies, subsurface reservoir modelling, engineering, energy, procurement, logistics, storage, project management- all parties find it difficult focusing on a common goal and streamline the decision process. Because it has long been thought that the EOR road map means planning for large scale EOR. However, that is false because there are very few full-field injections. The past strategy in EOR has led to a few pilot extensions implemented. Planning for large-scale EOR suffers from having the incremental oil, uncertainty in oil price, uncertainty in economic drivers and uncertainty in technical solutions for the expansion on the same time frame, which undermines economics. What it seems to be the only way to make progress with EOR, in reality, is that EOR should align with planning for quick oil response. We present here the steps to accelerate EOR in Grimbeek field from a 4-injectors pilot to 80 new injectors in a fast, less than 18 months deployment. We compare the capital and operating cost of multiple expansion scenarios. The scope is to accelerate EOR deployment opposite to the slow typical EOR workflow. We have seen the opportunity in accelerating the oil focusing on a simple modular strategy rather than iterating multiple possible engineering solutions to distribute the polymer across the field. NPV of the overall project is higher than the costs of delaying the injection or having to redo parts of the implementation along the deployment. Future optimisation is necessary for options of logistics, storage, in-situ skid connection and mounting along with by-pass remote control valves and remote control of skid injections. The building blocks of the strategy are containerised mobile skids containing ten pumps, polymer dispersion unit, and 30-metric ton silos. The mobile skids plug-in the waterflooding manifolds in an easy and fast connection. This injection scheme distributes polymer using the already implemented waterflooding in-situ installation. We focus on having a simple, standard and mobile system targeting fast implementation and fast oil response rather than large facilities.

In this paper, the flow field distribution of reservoir was calculated by commercial numerical simulation software, and the concept of streamline cluster was proposed. By extracting the spatial coordinates and attribute parameters of streamline particles, the vector flow field characterization parameters of streamline cluster potential, streamline cluster flow rate and oil content of streamline cluster are formed respectively. The Lorentz curve is introduced to evaluate the seepage velocity of the grid and to form a characterization method of reservoir flow heterogeneity. Based on the idea of balanced seepage field, the reconstruction methods of "building flow field", "planting flow field", "compensating flow field", "transferring flow field", "steadying flow field" and "controlling flow field" are established for different seepage field characteristic regions, and it is proved by an example. The results show that the property of streamline cluster between injection and production wells can effectively measure the horizontal and vertical development potential and displacement intensity of the reservoir, and the flow heterogeneity coefficient represents the fluid distribution difference in different development stages of the reservoir. The vector flow field characterization method is applied to a block in GD oilfield and its development status is evaluated. The vector reconstruction method established in this study is adopted to adjust the characteristics of different flow field regions. After the implementation of the adjustment scheme, the injection-production correspondence rate increased from 78.6% to 92.4%, the water drive control degree increased from 69.2% to 89.7%, and the EOR increased by 5.16%. The effect was obviously improved.

Gas-lift technique plays an important role in sustaining oil production, especially from a mature field when the reservoirs’ natural energy becomes insufficient. However, optimally allocation of the gas injection rate in a large field through its gas-lift network system towards maximization of oil production rate is a challenging task. The conventional gas-lift optimization problems may become inefficient and incapable of modelling the gas-lift optimization in a large network system with problems associated with multi-objective, multi-constrained, and limited gas injection rate. The key objective of this study is to assess the feasibility of utilizing the Genetic Algorithm (GA) technique to optimize the allocation of the continuous gas-lift injection rate in a network system of a Middle Eastern oil field with 43 gas-lift injected wells through numerical modelling and simulation studies. Reservoir pressure and water cut sensitivity studies are performed to investigate the potential impacts of these parameters on well production performance and production life cycle of the field. Sample economics analysis are exercised to broaden the understanding of potential benefit of the implementation gas lift techniques in the field from both technical and economic viewpoint. In addition, while application of GA is not a new idea, this paper elaborates the GA based optimization techniques for improving the oil production rate by implementing gas lift in a large Middle Eastern oil field. The optimization model is presented step by step, so it can easily be followed, and be used as a guide, especially by frontline production engineers involved in designing and development of gas-lift system towards optimally allocation of gas injection rate to individual well in a network system for a field with limited gas injection rate.

The digital transformation journey provides new opportunities for running simulations through cloud computing, with flexibility in hardware resources and availability of a wide array of software tools that can enhance decision-making. This work reviews the benefits of running reservoir simulations in a cloud environment and demonstrates the efficiency and cost savings. Additionally, a workflow for uncertainty analysis and history matching that integrates data analysis and machine-learning tools is presented. First, the hardware architecture must be designed to meet parallel reservoir simulation needs: significant message passing occurs between computer nodes, and for satisfactory performance, these nodes must be connected by a low-latency network, rather than be randomly located. Second, to ensure portability and easy replication across multiple cloud sites and platforms, the software performing the simulations must be containerized. Third, to reduce the time required to start a new simulation run, the Kubernetes platform is used to optimize resource allocation. Finally, reservoir simulation in the cloud is no longer merely the running of the simulation model, but it is integrated with data management and data analysis tools for decision-making. The cloud-based simulation services discussed herein exhibit good results during scale up, when a simulation operation requires a larger number of central processing units and/or greater memory, and also during scale out, when thousands of operation scenarios are necessary for history matching. The "pay as you go" pricing model reduces the time and capital costs of acquiring the new computing infrastructure to nearly zero, and the effectively unlimited scale-out capability can reduce the elapsed time for history matching by 80%. The availability of data centers in different regions is good for team collaborations. It serves the data management tool well to track history data, perform data mining, extract more information, and make decisions. Compared to traditional reservoir simulation, the cloud-based reservoir simulation software as a service model simplifies the process and reduces hardware acquisition and maintenance costs. Integrating intelligent data analysis with simulation helps quantify the uncertainty in the model and enables improved decisions.

This paper highlights several opportunities to maximize the total crude oil yield of typical Gas Oil Separation Plants (GOSP's), gas handling and crude oil stabilization systems. This can be achieved for existing facilities by optimizing operating parameters without capital cost or plant modification. Maximizing GOSP's yield (oil recovery) has many advantages such as revenue generation, reducing energy requirements of associated gas handling, mitigating export gas transportation challenges as well as reducing capital cost for new facilities. Throughout three case studies, this paper demonstrates the impact of operating parameters change in reducing GOSP's total oil shrinkage: Case Study-1: Pressure let-down optimization of multistage separation Case Study-2: Temperature optimization of compressors after-coolers Case Study-3: Temperature optimization of crude stabilization The analysis was performed for each case study utilizing HYSYS process simulation to establish the optimum operating window for the subject process area. The theoretical results were advanced by conducted field trials under governing operating procedures to validate the conclusion and further explore the benefits as well as the potential challenges of these opportunities. In case study 1, for high GOR GOSP where more than 3 stages of pressure letdown are required, pressure optimization of the intermediate and low pressure gas/oil separation stages achieved an oil output increase of 3.5 MBD for the same base rate (500 MBD) with dropping gas compression power requirement by 10 MW. In case study 2, for GOSP's where steady-state hydrocarbon condensate recovered from compressors after coolers knock-out drums is spiked into main Light crude production, optimizing air coolers operating conditions result in a gain of up to 2 MBD in export oil for the same base rate (200 MBD). Moreover, 50% drop in export gas water load can be achieved which helps mitigating pipeline corrosion challenges in gas transportation given the unavailability of a gas dehydration system in the facility. In case study 3, optimizing inlet temperature of light crude stabilizer enhanced column stripping capability and enabled meeting the required H2S and vapor pressure specification with minimum hydrocarbon liquids losses. A Reduction of 20 °F in inlet temperature resulted in savings of up to 2 MBD stock tank crude for the same base rate of 500 MBD in the expense of reboiler's duty.

The combination of unevenly distributed demographics and the recent industry downturn have resulted in an exodus of highly experienced workers from the oil and gas industry as employers constrained costs by reducing headcount. Retirement of highly skilled technical experts has further compounded these critical issues. The remaining workforce is talented, but many organizations are experiencing significant capability gaps that are driven from their workforce being inexperienced, under-trained, and lacking access to qualified mentors. Addressing capability gaps requires an understanding of what skills are needed. New leaders may not be aware of the full spectrum of technical skills, and which skills are best applied to technical challenges. Many leaders manage cross functional teams where several team members work in different disciplines. Once appropriate skills are identified by job functions necessary to perform the work, companies inventory skills and competency levels in their organizations. Individual development programs are developed utilizing available training and development resources to target the gaps and effectively raise the level of competency within the required timeframe. A complete program includes: Competency modeling and assessment Conventional classroom instruction and exercises E-learning libraries Virtual learning options In-house and virtual mentoring Business workshops and simulations Rotational assignments and "On the Job" (OTJ) training Consulting experts to fill gaps temporarily and allow time for staff development Subject matter experts to provide peer reviews to ensure quality Successful implementation of a competency based focused training and mentoring program drives companies to close the identified capability gaps and increase business performance. This presentation draws on several successfully implemented programs to demonstrate the applicability and relevance of the program's key elements leading the organization to an increase in overall workforce skill levels. These referenced examples describe key elements of a competency management system (CMS) implemented by E&P companies globally. The CMS system includes building competency models, developing employee and supervisor assessments, and creating learning plans for employees in both technical and business support positions. The competency models will reflect models that have been approved by the Society of Petroleum Engineers and the Society of Exploration Geophysicists, adding a global standard to the program. By using the CMS for assessments, senior management can clearly monitor and determine its current competency levels, measure its progress in eliminating competency gaps, identify the competencies that need further development, and update individual learning plans. The expected outcome changes the dynamics of personnel development from curriculum-based training to competency-based in order to accelerate the skills that are required for the company and their specific applications.

This paper describes a Virtual Drilling Reality (VDE) System, based on Virtual Reality (VR) technologies, designed and developed by Eni in collaboration with Saipem. The virtual environment is currently featuring last generation deepwater drilling rigs that are entirely virtualized and allows an immersive experience for Rig Crew and Drilling Engineers training, and in general for anybody who is interested in drilling rigs, equipment and operations. The system includes: a complete virtual tour of rig and equipment; the replay of drilling and rig operations chosen from drilled wells database; a virtual HSE induction at rig site virtual replays of real HSE incidents and rig Safety Drills; an interaction with Drilling Operations based on well drilling simulations; the execution of customized "missions", in single- or multi-player mode The new VDE can also be used as an overall well digital twin throughout the entire well lifecycle including well planning, operations follow-up and post-analysis. Configured for easy customization, the system allows extensions of virtualized rig fleet, modification and addition of the "active objects" in the repository, the preparation of tasks to be completed under the supervision of the trainers, play-back of operations, simulation of new drilling procedures and finally extra HSE incidents or emergency situations. State of the art VR devices and techniques, such as headsets, VR gloves and stereo goggles, are used for a highly immersive and interactive experience, while 2D PCs or 3D Screens facilities are also available. An initial version of the VDE has been used since 2018 in innovative training courses held in Eni's Corporate University. More recently, a well drilling simulator has been included in the system, realizing a full "well digital twin". Engineering experience was then gained both in well planning, operations follow-up and post analysis, applied to complex wells management. Main results obtained include: a safe familiarization with complex operations the optimization of operations, through realistic simulations an increased safety awareness an operation follow-up diagnostics support In summary, Eni's concept of the virtual drilling environment allows a fully virtualized system, with access to all rig workplaces, for a full immersion and interaction in a dynamic, physical and collaborative environment. The possibility to reproduce simultaneous activities and the enhanced interaction with all drilling operations and real life on board, provides a new and innovative well digital twin experience for improved training and engineering support throughout the entire well life-cycle.

The main objective of diversion is to enhance contact of the stimulation fluid with the reservoir. If the diversion is designed by trial and error, without proper understanding of physics behind particle size distribution, and pumped downhole the uncertainty will be high and it will reduce the effectiveness of stimulating job. Stimulating fluids pumped into a reservoir takes the least resistance path and goes into areas where often the stimulation is not required to increase production. The success of a hydraulic fracturing or acidizing treatment depends on maximizing the contact and distribution between the stimulation treatment and the reservoir. To achieve this goal, existing fluid paths must be efficiently temporarily blocked and divert the treatment fluid towards under-stimulated areas, which should maximize production. The diversion is being widely used but it is not being focused on optimizing completion via an engineering approach. This paper will present a comprehensive discussion around missing factors associated with jamming and plugging efficiency, particle size, particle shape, frictional parameters, particle concentration, opening geometry, rate during placement, and particles size distribution and ratio. It will clearly highlight the importance of optimizing completion and re-fracturing opportunities via diversion. Multiple experiments were conducted to quantify the effect of the different factors that dictate the overall goal of a successful diversion treatment. An analytical model based on computational fluid dynamics and discrete element modelling was developed, and calibrated with experimental results to optimize the different parameters that affect an optimum diversion. One of these key paramenters is the displacement rate during diverter injection, including determining the required spacers to minimize particle dispersion, ensuring the diverter pill arrives on formation intact and as designed to effectively create the temporary resistance required to effectively divert to under-stimulated areas.

Well-control management is nowadays frequently approached by means of mathematical optimization. However, in many practical situations the optimization algorithms used are still computationally expensive. In this paper we present Progressive Optimization (PO), a simulator-nonintrusive four-stage methodology to accelerate optimal search substantially in well-control applications. The first stage of PO consists in a global exploration of the search space using design of experiments. Thereafter, in the second stage, a fast-to-evaluate proxy model is constructed with the points considered in the experimental design. This proxy is based on Generalized Barycentric Coordinates (GBCs), a generalization of the concept of barycentric coordinates used within a triangle. GBCs can be especially suited to problems where nonlinearities are not strong, as is the case often for well-control optimization. This fact is supported by the good performance in this type of optimization problems of techniques that rely strongly on linearity assumptions, such as Trajectory Piecewise Linearization, a procedure that is not always applicable due to its simulator-intrusive nature. In the third stage, the precision of the proxy model is iteratively improved and the enhanced surrogate model is re-optimized via Manifold Mapping (MM), a method that combines models with different levels of accuracy. MM has solid theoretical foundations and leads to efficient optimization schemes in multiple engineering disciplines. The final and fourth stage aims at additional improvement resorting to direct optimization of the best solution from the previous stages. Nonlinear (operational) constraints are handled in PO with the filter method. The optimal search may be finalized earlier than at the fourth stage whenever the solution obtained is of satisfactory quality. PO is tested on two waterflooding problems built upon a synthetic model previously studied in well-control optimization literature. In these problems, which have 120 and 40 well controls and include nonlinear constraints, we observe for PO reductions in computational cost (for solutions of comparable quality) of around 30% and 50% with respect to Hooke-Jeeves Direct Search (HJDS), which, in turn, outperforms Particle Swarm Optimization (PSO). HJDS and PSO are simulator-nonintrusive algorithms that usually perform well in optimization for oil-field operations. The novel concepts of Generalized Barycentric Coordinates and Manifold Mapping within the framework of the Progressive Optimization paradigm can be extremely helpful for practitioners to efficiently deal with optimized well-control management. Savings of 50% in computing cost may be translated in practice into days of computations for just a single field and optimization run.

The magnitude of the phase velocities and turbulence, and the stability of protective sulfide scale affects the degree of erosion-corrosion in amine lines. Avoidance of high velocities, turbulence and stagnant regions can reduce the impact of erosion-corrosion in amine plant piping networks. Separated or stratified flow regimes influence the distribution and efficient spreading of corrosion inhibitor over pipe circumference. A combined process simulation and Computational Fluid Dynamics (CFD) modeling study was conducted to predict the multiphase flow regimes and phase velocities in the rich amine pipe segment between the rich/lean exchanger and the stripper column inlet. The objectives of the study were to determine the multiphase flow regimes in the rich amine line to stripper, and identify regions of locally high velocity relative to the mean velocity of the rich amine. A transient multiphase CFD model of the rich amine pipe segment used inputs from process simulation for different gas/liquid ratios ranging from low gas to high gas to predict and visualize the two-phase flow patterns and velocity distributions. Localized high liquid velocities and wall shear stresses were predicted in the pipe segments corresponding to observed corrosion. A key finding is that the multiphase flow regimes in piping of interest are invariant of the operating gas volume fraction ranging from 0.01 to 0.80. A set of recommendations were developed to mitigate the adverse flow regimes and corrosion potential to further enhance the acid gas handling plant operation and support the inspection unit in mitigating a corrosion environment.

Many operators are developing coalbed methane (CBM) reservoirs from Ordos basin on a regular basis, and fracturing is one of the key measures to increase production from this unconventional resource. Despite the long history and large volume for CBM fracturing stages in the past, the performance from the CBM reservoir is still often inconsistent and differs from expectations. It is necessary to have better understanding of the hydraulic fracturing dynamics in CBM to improve reservoir performance. CBM reservoirs are well known to be different compared to the conventional formations, and so fracturing involves different considerations. Three key components are integrated in this study to better understand CBM fracturing. Fracturing data from multiple wells are integrated into one database to exhibit a certain pattern of where the better production would be. With the observation from previous microseismic and offset well response, it is confirmed that the fracture geometry has reached to certain length. Based on this observation and analysis, simulation for pressure match is completed to illustrate the hydraulic fracturing geometry and propped fracturing geometry, which leads to an improvement plan for future work. The improvement plan for the fracturing in CBM is built upon the observation and analysis above. Unlike fracturing in conventional resources, onsite pressure observation and adjustment guidelines are suggested to achieve a better fracturing geometry in CBM because these have been shown to provide higher production over longer period of time.

This study describes the process followed to explain and understand the mechanical blockage in the flow path observed while displacing the cement slurries in long casing strings set with short rat holes. In most of the cases, those blockages ended with amount of cement left in pipe and significant remedial works. All the incidents were investigated involving casing design experts, cementing specialists and data analysts to understand the root causes. Mud logging unit, cementing and rig sensors data from several cementing jobs were analyzed in an integrated and holistic approach. Different software's were used to simulate and prove the theory that total elongation of the casing was enough to exceed the rat hole length bringing the casing in contact with the bottom of the well, and therefore blocking the flow path. In all the incidents, the issue was observed at the beginning of the slurry displacement stage where the entire volume of the cement was still inside the casing. Other possible causes of blockage (cement contamination, mechanical failures, loss control material,…) were also checked and ruled out. Hookload data was available to be analyzed whenever a conventional wellhead was installed, and the casing was held on the elevators during the cementing job. However, in some cases this information was not available as a compact wellhead was used. For those cases, it was necessary to drill out the shoe track using LWD to detect the location of casing shoe. Recommendations were made to add new loads the current casing design. Results will define the minimum rathole length and the maximum tension at surface experienced by the casing during the cementing job in both static and dynamic conditions. Also, it is important to properly estimate the rathole the physical measurement of the casing joints in the tally can carry measurement errors.

Cement sheath integrity under high-pressure and high-temperature (HPHT) conditions in the Maharaja Lela Jamalulalam (MLJ) field in Brunei is challenging to achieve because of the harsh downhole conditions. Pressures reach 15,000 psi [103 MPa], downhole temperatures rise to 165°C [330°F], and the narrow margin between the pore pressure and the fracture gradient makes mud removal and cement placement even more challenging. In addition, pressure and temperature cycling during production means cement selection with right properties is essential to maintain long-term wellbore integrity. The cement system must deliver cement mechanical properties that can withstand the downhole stresses over time. Mechanical failure of the cement sheath would create a path for wellbore fluid migration that could result in sustained casing pressure (SCP) or interzonal communication. This paper will discuss the challenges of cementing in the tight pore-to-fracture window in the MLJ field, and the design and placement of one of the world's heaviest (2.48SG [20.7 lb/gal]) flexible and expandable resilient cement systems. Wells in the MLJ field reach into a deep reservoir (4500 to 5000 m true vertical depth, TVD) where the pressures can reach up to 15,000 psi with bottomhole static temperatures reaching 165°C. The well is drilled using 2.18 SG [18.2 lb/gal] mud weight, and the production string is pressure tested at 15,000 psi; during the drilling and completion, the temperature variation is on the order of 60°C [108°F]. Based on the above well conditions, advanced computer-based simulations were used to determine the cement mechanical properties required to withstand the pressure and temperature changes. To achieve the required mechanical properties, special blends were prepared with engineered particles to impart flexibility and expansion for a 2.48 SG cement system. To manage the cement placement, state-of-the-art cementing design software was used to accurately simulate the bottomhole circulating temperatures and pressures during placement as well as to simulate pipe centralization; a 3D model for fluids displacement also proved valuable.

Liner deformation is a challenging problem in deep gas wells that are normally associated with poor borehole structural integrity. It occurs usually during the hydraulic fracturing process when the tensile strength of cement around the liner is compromised, and is most likely to occur due to the void structure inside the cement sheath. In routine hydraulic fracturing design, the evaluation of cement and its interaction with the liner and formation is normally not conducted to assess the liner mechanical integrity. Therefore, liner deformation may occur in poorly constructed boreholes, which could lower the cement strength on the external boundary of the liner by allowing air voids to form. This paper presents numerical analysis of liner structural integrity based on the presence of voids in the cement sheath. A better understanding of the liner mechanical integrity in smaller gauge boreholes is key to minimizing and/or avoiding liner deformation in deep gas wells.