The generally overlooked implications of intentional or unintentional overdisplacement of shoe track cement in production casings, resulting in what is commonly known as a wet shoe, are discussed in addition to how these implications/risks have been addressed and mitigated with recent developments in float equipment technology and operational methods. Additionally detailed are the operational, cost, and production efficiencies afforded by an engineered wet shoe system for primary cementing and completion operations. To utilize an intentionally overdisplaced production casing shoe track, or wet shoe, a float valve was developed, tested, and manufactured with the intent to be used as an independent mechanical barrier, preventing inflow of hydrocarbon into the casing. This was accomplished by performing a float equipment qualification, meeting the requirements in API SPEC 10F (2018) , and exceeding the requirements with additional testing comprised of static high-pressure and low-pressure testing with nitrogen to simulate formation gas pressure during cement phase change and before completion. Each discrete manufactured valve was also tested with low-pressure gas to validate each valve was fit for service before deployment. During a 20-well trial, a typical float check was used to test the barrier in place at the conclusion of cement displacement. Wellhead pressure was then monitored to confirm gas-tight integrity of the float equipment over time before completion operations. New technology using float equipment, conventionally not regarded or considered for use as a mechanical barrier, was successfully developed and qualified for use as an independent mechanical barrier in uncemented shoe tracks and successfully deployed in low-permeability wells to maintain a two-barrier system without shoe track cement. This success was the culmination of the equipment design and qualification process with operational risk assessment/mitigation.

Artificial lift pumps are widely used in oil production, and among them, sucker rod pumps are conceptually the simplest ones. The reciprocating movement of the plunger triggers the opening and closing of two ball valves, allowing fluid to be pumped to the surface. These valves are subject to long-time erosion and fail as a consequence of this damage mechanism. We demonstrate that understanding the principal damage mechanisms in the necessary depth and breadth requires a thorough examination of the fluid dynamics during the opening and closing action of the ball valves. This paper describes the basic ingredients and results of fluid–structure interaction model that simultaneously computes the fluid flow in the traveling valve, the standing valve, and the chamber of sucker rod pumps during a full pump cycle in an efficient and accurate way. The simulations provide necessary insight into the causes of valve damage for realistic standard as well as non-ideal operating conditions of the downhole pump. In particular, simulations based on real pump operating envelopes reveal that the phenomenon of so-called ‘‘mid-cycle valve closure’’ is likely to occur. Such additional closing and opening events of the ball valves multiply situations where the flow conditions are harmful to the individual pump components, leading to efficiency reduction and pump failure. The computational-fluid-dynamics model based on the finite-element method serves to accurately describe the opening and closing cycles of the two valves. Most importantly, this approach for the first time allows an analysis of real operating envelopes, derived from actual dynamometer cards. The combination of stroke length, plunger speed, fluid parameters, and velocity at any point inside the pump can thus be investigated at any time during the pump cycle. The flow parameters identified as critical in terms of damaging pump valves or other pump components can set the basis for taking measures to avoid unfavorable operating envelopes in future pump designs. Our comprehensive flow model may support field operations throughout the entire well life, ranging from improved downhole pump design to optimized pump operating modes and envelopes as well as in material selections. It is suggested to aid in adapting pump operating conditions to create an ideal interaction between the valves and avoiding the "mid-cycle valve closure". Specifically, a so-optimized pump design is expected to drastically extend the operation time before failure of sucker rod pumps. Finally, this type of simulation will speed up new pump or pump component development, and can eliminate or at least reduce the necessity of extensive and costly laboratory testing.

PACT (Pressure control ACTuator) is a newly developed, all-electric wellhead- and production tree valve actuator for enhanced well control and fail-safe handling of emergency situations. The actuator was developed under a Joint Industry Project (JIP) by Equinor, Baker Hughes and TECHNI. PACT is designed for mission critical operations offshore and is subject to stringent safety design requirements. The actuator employs a patent pending fail-safe mechanism with extremely fast closing time to ensure containment during emergency shutdown. Opening time is 30 to 60 seconds (depending on valve size) and adjustable closing time of 4 to 8 seconds (valve closing in less than 1 second has been demonstrated). It is designed to be a drop-in replacement for NoBolt™ CHA actuator solutions and is suitable for most standard wellhead and tree designs, sizes and pressure ratings. Electric actuators offer significant CAPEX savings over hydraulic actuator systems by eliminating the need for costly hydraulic control systems (HPU), associated hydraulic lines and umbilicals as well as saving deck space and weight. Electric actuators also offer significant OPEX savings over hydraulic actuators by eliminating the need for specially trained personnel offshore during periodic testing and associated post-actuation flushing of hydraulic lines. Environmental impact is reduced by eliminating high-pressure hydraulic oil lines with associated risk of spills and removing the need to transport personnel offshore which reduce total CO2 emissions. The PACT development program was initiated in 2017 and has resulted in an actuator solution at Technology Readiness Level (TRL) 4 (on 0 to 7 scale) with planned TRL 5 testing yielding it ready for field installation.

Intelligent Completions (IC) are deployed with the high hopes of frequent data utilization and zonal selectivity maneuver to optimize production continuously. The permanent downhole presence of measurements like pressure, temperature, rate, water-cut, gas-break provide downhole indicators and trending analysis of production performance and injection conformance. These are utilized not only to maximize hydrocarbon production but also to reduce surface handling of water and/or gas, improve injection efficiency, and reduce carbon and environmental footprint. However, the reality could be different from the evaluation stage to the application stage. The asset production engineers or the reservoir engineers face real challenges when it comes to design, downhole installation, data transmission, real-time analysis, and optimization to deliver the real value of the initial investment. These suboptimal application factors, multiplied by the complexity of IC deployment and execution with existing hardware constraints, have limited the progression towards digital well technology. By analyzing such trends, a new advanced completion optimization methodology has been devised, leveraging the latest technology and innovation, IC deployment simplification, and electrification efforts in the industry. This paper analyses the underutilization reasons of digital well technology, such as - the ability of design and implementation, the downhole data measurement, complexity of modeling and optimization, and the bottlenecks in applying the learning from the Intelligent Completions data to optimize production. It is then compared to the easing transition to the future digital-wells, advanced modeling capabilities that are driving the oilfield digitalization by next-generation Intelligent Completion. This digital transition ranges from ease-of-deployment to ease-of-optimization and eventually towards cloud-enabled decision making. The new era of IC electrification deployment and digital solutions are twinning to provide an integrated platform to maximize value and justification for more future digital wells. A fully digital system to control reservoir and optimize the product is becoming a reality with the transformation of modeling capability and enabled by simplification of IC deployment, and this is the digital future of IC optimization. This digital solution is continuously feeding asset subsurface, modeling, and optimization team with productivity or injectivity indexes and other inputs required for reservoir steady-state and transient evaluation. The IC industry continues to be integrating into the new solution frontiers of logging-while-producing, the testing-while-producing capability to the eventual optimizing, modeling-while-producing future, leading towards a true digital oilfield of the future.

Results of multiple years of periodic aerial methane surveys over Pioneer Natural Resources’ operations footprint, comprising approximately 680,000 acres in the Permian basin, are presented, including impacts to operational efficiency, cost, and methane emissions mitigation. Aerial methane detection was performed using a light-aircraft mounted, integrated methane imaging spectrometer. Geo-referenced methane emissions data combined with real-time geo-referenced optical imagery provided accurate methane localization and source attribution. Ground inspection teams used optical gas imaging technology to validate the aerial results and dispatch repair teams. Externally validated leak quantification provided by the spectrometer further allowed accurate measurement of methane mitigation. Aerial methane inspections of nearly 10,000 operations sites per survey, including wells, tank batteries, and all associated equipment, are reported for multiple years of periodic surveys. The data shows a complete picture of the most significant methane emissions from the Pioneer operations footprint over consecutive years and has proven beneficialinvaluable for enhancing operational efficiency. Based on the data, Pioneer has been able to identify the areas of highest impact and focus operational resources on those improvements. Surveys identified types of emission sources that can be addressed immediately within Pioneer operations and areas where Pioneer would need to work with others to improve overall gas takeaway challenges in the Permian basin. Furthermore, Pioneer has reduced leak detection and repair (LDAR) costs significantly by reducing both driving time and ground-based inspection time. We estimate more than 2500 work hours and 1000 driving hours, were saved by each aerial survey. Between 2016 and 2018, the company's methane intensity has declined approximately 41%. Aerial survey results have allowed Pioneer to significantly reduce methane emissions while simultaneously improving safety and efficiency, reducing costs, and reducing vehicle traffic. To our knowledge, this is the first multi-year, comprehensive, aerial periodic methane survey of an entire upstream oil and gas operation's footprint. We're now able to report on the benefits of this paradigm shift away from conventional LDAR surveys. Although the challenge of reducing methane emissions can be daunting, the results from aerial monitoring show that with a technology and data-driven approach, operators can significantly reduce emissions while simultaneously reducing costs and improving operational efficiency.

This paper shares The Delta Deep Marine (DDM) experience in developing stacked reservoirs subsea fields by implementing smart completion for reservoir management, surveillance & production sustainability. Smart well system are composed of permanent downhole sensors & downhole flow control valves that allow recording, evaluating, & actively managing production in real time remotely without any well interventions, which facilitate to improve reservoir management strategy. Once a smart well is completed, valves can independently control each zone of the well, such as controlling zone production when it starts producing water, shutting water-flooded zones or in defensive mode, avoid sand production by adjusting of smart valves settings to safe guard against losing the well. This paper contains different case studies in applying smart completion & their positive effects in the field development plans. The benefits of optimal application of smart well completion technology in DDM are numerous. These include reducing number of development wells so reduce CAPEX, developing marginal opportunities to improve economics, avoiding well intervention for zonal control to reduce the OPEX, reducing water production to improve subsea network efficiency & reduce water-handling issues, reducing geological uncertainty by proper frequent zonal test, reducing risk of losing the well by control each zone independently to avoid sanding, managing commingled reservoirs with different characterization properly & maximizing reserves. In addition to auto gas lift oil zones without a need to subsea artificial lift infrastructure that allows completing oil zones as an upside gain. Smart completion was identified as the best option to meet deepwater requirements in producing this field with minimum number of wells without sacrificing targeted production profiles.

This paper presents the analysis and results of the Jet Pump (JP) applications in the two oil fields: Well -A, for customer in U.A.E, and Well-B for customer in Oman. Well-A was a deviated well with 3-1/2-inch single string completion. The tubing-string was equipped with three Side Pocket Mandrels (SPM). Based on preliminary screening for Artificial Lift Systems (ALS) against the provided well data, the jet pump system was found the most suitable ALS method. Jet pump was evaluated for its efficiency in reviving a dead well with rig less installation using Jet Evaluation and Modeling Software (JEMS). Thus, a reverse circulation JP was straddled across the last SPM in the tubing using two tubing packers. The power fluid was then injected through casing which entered the JP to create the drawdown required to bring the formation fluid through tubing to the surface. The dead well was produced successfully at different injection pressures and rates for four months. The production results were compared to the theoretical model of JEMS to assess the JP performance. The Well-B was a newly side tracked well where customer intended to use a jet pump for offloading the kill fluid of well from its last zone. A 2-7/8-inch bottom hole assembly of JP was run at 9,348 ft depth during the well completion. Jet pump was freely dropped in the well to offload the kill fluid and revive the production. Rig pump was used to inject power fluid at high pressure in the tubing and returned fluids were taken from the annulus. Constant samples of produced liquid were taken to ensure the kill fluid has been offloaded and the reservoir started contributing its fluid. Jet pump was retrieved with the help of slick line once satisfactory results were received at the surface. The well was successfully offloaded at around 900 bbl. of gross fluid using JP technology.

This paper introduces a new water controlling technology to manage water production and improve production performance in an offshore oilfield in Bohai, China. Q oilfield is a typical heavy oil reservoir, mainly developed by horizontal wells. One of the main challenges for the production is the high water cut. Most of the wells experience water breakthrough within one year after put into production and produce for long time with water cut higher than 90%. Besides, the strong anisotropism of the formation aggravates the water breakthrough and makes water control work more difficult. In 2019, a new combined water control technology was applied to manage water influx in horizontal completions. In this technology, the annulus between the wellbore and the inner ICD (inflow control device) /AICD (Autonomous inflow control device) screen is filled with light-but-hard particles. In this paper, the barrier built by the fine particles is called continuous-packer. The existence of this barrier plays a similar role to mechanical packers between each ICD/AICD screen, thus the axial flow of the produced liquid is prevented in the horizontal section. Besides, the ICD/AICD screen is equipped to limit the liquid inflow of each segment based on the design. The purpose of equalizing production profile of the horizontal section achieves through the cooperation of the continuous-packer and the ICD/AICD screen. Untill now, this new technology has been used in more than 6 wells in Q oilfield, including both producing horizontal wells with high water cut and newly drilled wells. The production results show that the water cut reduces about 10% and the oil production increases for the high water cut well. The water breakthrough time and the water cut increasing rate is slower for the new wells comparing with near wells. The successful application of this technology demonstrates its validity for the offshore heavy-oil reservoir with active bottom water. It also provides a new method for the water controlling work for the offshore wells in Bohai oilfield. A detailed plan has been finished to implement this technology in more wells in 2020.

Long horizontal wells in naturally fractured carbonate reservoirs often exhibit very high water-cut within months of production because of the early arrival of water from natural fractures. Passive inflow control devices (P-ICDs) have been used globally to balance influx, delay water or gas breakthrough to prolong well life. However, some wells have continued to experience high water-cut despite the control measures. Image log review has revealed the uncertainty is in the identification of fractures and its conductivity networks. Two additional zonal control technologies are presented in this paper: on/off ICDs and intelligent (IC) or smart completions in comparison. A software-based 3D reservoir model was built to represent a horizontal oil-producer in a fractured carbonate reservoir penetrating a thin oil rim. The first model simulated well production performance in a well with on/off ICD. Intervention was replicated in time (i.e., taking longer) to shut-off ICDs. The second model evaluated production forecast over the same period for the same well, this time equipped with an IC in the open hole (OH). Actions in this case were taken right away from the surface (i.e. without downhole intervention) to identify and restrict or shut-off intervals with water breakthrough. Time-lapsed 3D reservoir model calibration is possible with ICs as they provide real-time downhole pressure and temperature across each interval. The timely control of zonal valves from surface actuation reduced production of water or gas. On/off ICDs, on the other hand, necessitated scheduling a production log (PL) to confirm the interval of water or gas breakthrough and performing coiled-tubing (CT) intervention to shut-off the problematic zone. Intervention comes at cost of interrupting well production and reducing net oil recovery. A simplified cost-benefit analysis of both cases showed that despite a higher initial capital investment in ICs, well operating costs were substantially lower with higher oil recovery. In IC solution, costs for running production logs and intervention tools were eliminated and so was the risk of losing these tools in the hole and the loss in production during the intervention period. Continuous monitoring of downhole pressure data helped reservoir characterization and prediction of reservoir production behavior without compromising production on-stream time. A comparison of different reservoir flow control devices suggests that ICs are the optimal choice in some fractured carbonate reservoir conditions. They provide real-time monitoring of each producing zone and surface control of the flow control valve (FCV) settings in real-time as reservoir performance changes. They enable production testing evaluation—without production logging and interventive shifting with CT, i.e. to determine the source of water entry and optimization of multi-zone production without downhole intervention.

Reservoir pressure depletion and liquid loading depress production in mid-to late-life producing wells. While pressure depletion can be difficult to combat and requires large scale solutions, liquid-loaded production tubing is easily remedied by on-site, individualized artificial lift solutions, such as sucker rod pumping, plunger lift, or gas lift, to name a few. A recent experimental study of Coutinho et al. (2017) , using 2,788 ft depth vertical well with 2.88-inch ID tubing and 4.89-inch ID casing, shows that liquid-assisted gas lift (LAGL) processes can overcome difficulties in conventional gas lift, one of the most popular artificial lift methods in both onshore and offshore environments, and aid in cost reduction for operations by decreasing the onsite energy and infrastructure needs to unload a well. Following the outcome of the experimental study, this study investigates how to further refine LAGL operations by conducting transient computer simulations using OLGA. The first step is to match the experimental data (i.e., history of bottomhole pressure and injection pressure) to extract model parameters for the simulations to follow, the second step is to perform 119 different simulation runs as well as analysis of resulting pressure and liquid-holdup histories in a wide range of gas and liquid flowrates, and the last step is to show how to implement the optimization technique by using the contour maps of variables and parameters of interest to optimize. The results show that the two contour maps of required maximum injection pressure and liquid holdup in the tubing, as a function of gas and liquid flowrates, can serve as a useful means of seeking the optimum operating conditions. In addition, it is also shown that there are multiple sets of two contour maps, equivalently, to be employed for a similar analysis depending on various field scenarios or constraints (such as compressor capacity, limited gas supply, and separator capacity). Pressure loss and phase fraction, through complicated multiphase flow physics and flow regimes, play a key role behind the presence of optimum operating conditions during liquid unloading process.

A new, fully automated completion system contributed to improved safety and efficiency of plug and perforate completions on 34 horizontal wells completed in west Texas Delaware Basin between 2018 and 2020. By enabling nearly continuous frac operations and wireline transitions in three minutes or less, the new system helped reduce the average time-to-complete a well by 38% compared to the average performance on the operator's nearby wells completed using a traditional latch.

In the last decade, the oil and gas industry has been extended in direction of Digital Oilfield (DOF) approaches (i.e. using smart phone/watch, historians and data management) in many fields such as drilling and health-safety-environment, to improve efficiency and reduce cost. DOF helps in real-time data transfer, monitoring, data cleaning and processing, interpretation, and visualization to make an optimal decision. Moreover, the DOF system has an ability to self-learning via feeding the labeled historical data to update the entire model. Monitoring, surveillance, diagnostic and modeling management can be made by a person(s) observing the job remotely, rather than locally, with potential for significant cost savings by cooperating various experts to data analysis. Also, real-time system creates continuous well performance monitoring system, thus the system provided a platform for better understanding of the effects of the reservoir behavior which could be reflected on optimizing production operations and enhanced health, safety and environment. In this project, a controlling system is used to maintain and treat pH of drilling mud, as well as using smart devices to monitor the data at real time. This paper describes a lab-scale flow loop drilling system with real-time monitoring and treatment systems for mud H2S contamination control. The readings of the pH level, electrical conductivity, and pH neutralization chemical valve opening are real-time monitored and control remotely via Internet by using a smart phone to view the streamed data to authorized person as trends for each parameter/sensor. The results show, the proposed system monitors the streamed data for detectable events and triggers automated notifications to personnel who are ‘following’ the job. In this manner, an operator can be alerted when the H2S is indicated by a significant change in EC accompanied by decreasing pH, an automatic mud treatment control system, and monitored by the smart devices, activates to restore and maintain a targeted pH value. The presence of H2S in hydrogen sulfide bearing formations introduces significant risks due to its extreme toxicity and its corrosive effects on drilling rig equipment. To ensure protection of drilling operation personnel, a real-time pH/EC monitoring system is developed using a remote and smart control unit that could send alerts and control the treatment process while simulating and monitoring H2S influx on smart phone and smart watch. This project demonstrates the usage of an edge technology in petroleum industry that meets future aspirations of oil and gas industry, which is represented by the self-learning system that could improve the results and increase its accuracy by using the continuous feed of data to the system database.

Successfully deploying a single trip completion system in a deep-water environment requires an innovative technical solution to address the risks that come with this environment. Following a request from the operator for a deep-water single trip solution, a number of different system options were proposed. Each system was evaluated against the operator’s requirements, and a Radio Frequency Identification (RFID) technology-based system was selected as it offered the greatest flexibility in both activation and contingency methods to meet the demands of the project. It was proposed to hold a 2 stage System Integration Test (SIT) at a test rig in Aberdeen. The first SIT was performed with a small number of tools that could be setup in different modes to prove the system’s logic against the operator’s expectations. Whilst this was conducted successfully a number of learnings and operational optimisations were captured. These were fed into a full-scale SIT which was deployed at the same test rig. This second SIT involved a complete representation of the single trip system and was designed to test the final system logic prior to deployment into an offshore environment. The system was then installed successfully in November 2018, on a subsea well, offshore Nigeria with no intervention. It resulted in an operational time saving of at least 60% over the previous best recorded time for a conventional two-trip completion from the same rig. This represented a step change in operational efficiency and will now be the operator’s base case completion methodology as they develop the field further. This is the first time a single trip completion has been deployed in this fashion in a deep-water, offshore environment. The demonstrable step change in operational time and resultant project OPEX savings, proves that the use of RFID and remote actuated tools within completions offer excellent alternatives to traditional methods.

This abstract is submitted as an addendum to SPE-188853-MS, which deliberate about Improving Sweep Efficiency by Zonal Isolation Using High Expansion Ratio Inflatable Plugs. "M" field contains medium gravity viscous crude (10-20cp) in high permeability sands. Application of EOR technique is considered pivotal in sustaining the plateau production rate and maximizing the ultimate recovery from this field. "M" field is currently under polymer flooding with wells completed in a 5-spot pattern. The high viscosity crude in this field, with an unfavorable mobility-ratio with water, mandated the need to switch from water to polymer flooding. Even though good sweep improvement was observed in most of the patterns, a few pattern producers didn't respond to polymer flood as expected. They exhibited poor sweep efficiency which resulted in bypassed oil and early water/polymer breakthrough. The poor sweep efficiency adversely affects the project economics by reducing the Expected Ultimate Recovery (EUR) and increasing the opex associated with produced water handling. Paper SPE-188853-MS outlined how the installation of "high expansion ratio inflatable plugs" in the pattern producers, improved sweep efficiency. This paper adds further case studies to it, carrying forward the success of these Plugs. Moving onward the process of isolation based on detailed analysis of pattern flood producer wells which were shut-in, due to high water-cut and production handling constraints. Saturation log were carried out to locate the poorly swept sand zones. Also, since most of the wells are sub hydrostatic and exist on artificial lift. N2 assisted PLT were carried out to identify high water cut zones and accordingly zonal isolation of such high water cut zones were planned. Temporary isolation was required to accommodate plans for future ASP (Alkaline Surfactant Polymer) flooding. Both mechanical and chemical isolation methods were explored and accordingly well candidates were identified for each of the methods for isolation. Mechanical isolation methods are discussed in the paper (chemical isolation being discussed in a separate paper). Last paper gave insight about plug passing through a minimum ID of 2.3" and set in a 7" production casing. After this campaign, more candidates with plug setting section of 9-5/8" Casing & 4-1/2" Screens were selected. Plug setting with Coil Tubing & E-line were explored and executed. The jobs were successfully conducted in around 30 producer wells. The isolation resulted in a 3-4-fold increase in the instantaneous oil production with around 40% drop in produced water cut. This demonstrated how the treatments improved the selective drainage of the poorly swept sands by allowing preferential movement of flood front in these sands. To support selective treatment of injector wells for sweep bypassed oil sands, through tubing inflatable straddle packer acidization jobs are being planned to further increase the injection in poorly swept zones.

Objectives/Scope Majority of the world's gas lifted wells are under-optimized owing to changing reservoir conditions and fluid composition. The gas lift valve (GLV) calibration is required with changing conditions. Apart from that, an allowance needs to be kept so that the valve change remains valid for longer time. Compounding this, when adjusting gas lift parameters, it was not easy for the gas lift operator to make data-driven decisions to assure continuous maximized production. These challenges are further amplified with dual completion strings: fluctuating casing pressure; unpredictable temperatures due to the proximity of the two strings; and inability to individually control the injection rates to each string. String dedicated to the formation with lower productivity and reservoir pressure tends to "rob" gas from other string. Operating philosophy in such cases end up producing from one string. Production optimization in such cases requires frequent intervention with attendant costs and risks thus presents an opportunity to re-imagine gas lift well design. Methods, Procedures, Process ADNOC in collaboration with Silverwell developed a Digital Intelligent Artificial Lift (DIAL) system, which consists of multiple port mandrels to be placed at GLV depths. These mandrels are connetced to the surface operating system with a single electrical cable. The ports can be selectively opened or closed by sending an electric signal from the surface unit. In addition, pressure and temperature sensors are also placed which help record these parameters in real time. Such a system enables the choice of depth, injection rate, loading and unloading sequence controlled from the surface. Realtime optimization is possible as pressure/temperature data helps draw accurate gradient curves. This system makes gas lift optimization possible in dual gas lift wells. Results, Observations, Conclusions It has been estimated that this technology delivers a production increase approaching 20% for single completion wells, and exceeding 40% for dual-string gas lifted wells. Recognizing this opportunity, a business case and implementation plan were developed to pilot a dual-string digitally controlled gas lift optimization system. Novel/Additive Information This paper will describe, the screening phase, business case preparation, risk assessment and validation process, leading to this 1 st worldwide implementation of a fully optimized dual completion gas lifted well. Implementation plan of novel digital gas lift production optimization technology in an onshore dual completion well. The completely original approach increases safety, efficiency, operability and surveillance.

While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE). The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year. Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment. The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production. Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production. With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives. It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas. This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations. Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.

Current multistage hydraulic fracturing operations in shale are costly, environmentally challenging and inefficient. Multistage hydraulic fracturing operations already represent close to 60% of the total drilling and completion cost for each shale well. The industry studies reported that based on data evaluated in multiple shale basins in North America alone that up to 50% of the clusters and stages do not produce in geometric completion design. Shale E&P operators need more accurate, cost-efficient, timely and actionable data on the performance of individual fracturing stages and intra-well communication to enable improved decision-making and optimization of multistage hydraulic fracturing and completion strategy, as well as overall field development. This paper will describe a revolutionary smart tracer portfolio testing and design for multistage hydraulic fracturing stimulation. The technology enables the next generation of smart tracers coupled with advanced sub-atomic measurements that significantly reduce the completion cost and double the efficiency of the hydraulic fracturing treatments. An automated process with stringent quality control assured precise tracer addition onsite and provided accurate and actionable completion diagnostics results at fraction of the cost for high-cost measurements (e.g., PLT, DTS & DAS). The integration of smart tracer portfolio with intelligent-completion diagnostics for E&P customer enabled by performance-flow-profile data. This data used to optimize completion strategies, achieve optimal production per foot, and reduce completion cost. Follow-up big-data analytics and 3D fracture-modeling delivered accurate, calibrated, actionable, and cost-effective completion-diagnostics results. Since tracer data are captured over several months, E&P operators are captured access to continuous flow profiling data to optimize well performance routinely when new completion-diagnostics results are received. This will enable E&P operators to significantly reduce operating cost and optimize production in shale wells.

Petrobras has faced several challenges concerning inorganic scaling in the Pre-salt cluster. Scale prediction plays an important role on well completion selection and supporting to define better alternatives for chemical injection location. However, predicting scale in wellbores is traditionally performed based on thermodynamical equilibrium of the formation water under static conditions. This strategy leads to conservative results since it neglects hydrodynamics and kinetics of the scaling process. This paper proposes a new approach to predict scaling in downhole conditions. The study seeks to contribute on the comprehension of the effect of fluid flow and equipment geometry variation in the crystal deposition process in intelligent well completion equipment. Such completion devices act in managing the fluid flow influx from different reservoirs or multiple zones of the same reservoir. Despite the positive aspects of this technology, some authors have been pointing out some problems associated with specific applications of these tools. The most common issues are related to the considerable pressure differential and the occurrence of calcium carbonate (CaCO 3 ) scale. The pressure drop in this tool induces the flash liberation of CO 2 from the aqueous solution. Consequently, the chemical equilibrium is displaced towards the direction of precipitation of CaCO 3 in the flow stream. This paper proposes a new approach to predict scaling in downhole conditions and aims to quantitatively evaluate the calcium carbonate precipitation on the smart completion element internal surfaces. Computational Fluid Dynamics (CFD) along with discrete phase modeling (DPM) is employed to simulate the transport and adhesion of the calcium carbonate crystals on the device. The valves geometries consider the main features observed on the field according to different suppliers, accounting the different possibilities of completion geometries for Brazilian Pre-Salt environment. The results showed the tendency of scale deposition pointing out hot spots in several different completion accessories at downhole conditions. A better understanding of the scale potential has influenced the decision-making process on the completion design and workover alternatives in the Pre-salt wellbores.

This paper discusses component developments, validation testing, and yard testing of the subsurface process and reinjection compressor (SPARC) prototype tool approaching downhole flowing conditions (≈1200 psig and > 225°F). This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface. A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing. The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and > 450°F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls. This equipment will allow for the reduction of costly surface facilities to process, compress, and reinject produced gas into North Slope fields and some oil and condensate fields elsewhere globally, which are limited in liquid hydrocarbon production because of surface gas processing facility limitations. Another potential use of the SPARC technology is as an artificial lift mechanism for gas reservoirs. Using the SPARC as a gas well artificial lift system would require a redesign of the SPARC with an electric motor as its power source in place of the turbo-expander. However, no new technology breakthroughs are necessary because the technology has already been developed with the SPARC design. To date, there have been no small gas compressors, turbo expanders, and other necessary equipment built and tested that can be run through 4 1/2-in. tubing/casing and operate autonomously at downhole conditions. This technology opens up the possibilities of additional relatively inexpensive gas recycling on the North Slope and other condensate fields worldwide.

In the onshore field in the Northern part of Thailand, the wells are typically produced with gas lift and converted to beam pump later, using the annulus space for gas separation. In the past, the completion string must be replaced to switch to beam pumps. However, with the new Hybrid completion, the existing completion can be used, and the amount of workover is reduced. In the new Hybrid completion, two sliding sleeves are installed in the tubing string, allowing us to utilize both artificial lift methods without replacing the tubing. To produce the well with gas lift, both sleeves are closed, and the well is produced normally. When converting the well to be produced with a beam pump, both sliding sleeves are opened, a plug is set above the lower sleeve, and a downhole pump installed above the upper sleeve. This forces the wellbore fluid to flow out to the annulus through the lower sleeve. Since the liquid level is higher than the upper sleeve, most of the gas travels up the annulus while the liquid traverses through the upper sleeve from the annulus into the tubing. The liquid is then pumped along the string with a beam pump. This method acts as a gas separation mechanism to prevent gas lock and reduce efficiency problems for beam pumps. The flexibility to switch between the two artificial lift methods allows us to handle the dynamic wellbore and reservoir conditions more efficiently. The Hybrid completion has enabled us to (1) handle a wider well productivity range, (2) significantly lower the cost of workover, (3) decrease the hazards exposure during operations, and (4) produce oil and gas faster, favoring the economic return.