Inflow Control Devices Research Articles

The Development and Application of a New Water Control Technology with Fine Segmentation Features

To counter the high water-cut issues in the later production stage of horizontal wells in the western South China Sea, a water control technology that combines inflow control devices and light proppant has been developed. The development of the new technology combined both flow theory analysis and physical modeling methods, to reach a conclusion that the axial flow resistance of a gravel packed screen annulus is much higher than its radial flow resistance, utilizing this conclusion, the inflow control screens can be gravel-packed to balance the production profile along the horizontal wellbore, with a better sand control effect. Comparing to the conventional water control methods, the new technology’s advantages include: no need to pin-point the water production location before water control jobs, little risk of damaging the reservoir during operations. The new technology has been applied in oilfields in western South China Sea, after implementation, the experimental well produced 30m3/D more oil at 20% less water cut, which provides a new option of water conformance technologies in offshore horizontal wells.

English

Inflow-control devices (ICDs) were developed to avoid coning problems in long horizontal wells mainly in heterogenous formations, but cause some additional drawdown which does not contribute to rate increase. This rate reduction is seen to be impairment to the productivity of horizontal wells. Therefore, horizontal wells that are equipped with ICDs require a pre-quantification of their productivity by determining skin caused by each ICD nozzle size. This will help prevent additional expenditure that will be spent for a corrective horizontal well intervention. Many authors have proposed equations that can be used to estimate skin due to damage, partial completion, slanted well and perforation. No author has provided a skin equation that can be used to estimate recoverable and productivity loss that may result from the use of inflow control devices. In this work, a 3D numerical model which includes inflow control devices along horizontal wells was used to investigate reservoir and production performances of various ICD nozzle sizes. Different productivity losses from different nozzle sizes were seen as skin and a 0.002ft2 ICD nozzle flow area estimated to have a zero skin. Consequently, a simple equation for calculating this skin due to restricted fluid entry through ICD nozzles was derived. The derived equation which shows insignificant deviation from skin equation is then used for selecting the right nozzle size for production and recovery optimization from horizontal wells. Key words: Inflow control device

Use of Smart Controls in Intelligent Well Completion to Optimize Oil & Gas Recovery

For the past few years, the oil and gas industry has faced several economic, geographic and technical challenges largely due to decline in crude oil prices and market volatility.
 In the quest to address some of these challenges to accelerate production and subsequently maximize ultimate recovery, operators are limited to remote hydraulic and electro-hydraulic monitoring and control of safety valves providing the means of obtaining downhole production data which demands periodic well intervention-based techniques with risk of loss of associated tools. This has highlighted the need for companies to adopt new technology to take advantage of low crude oil price environment, optimizing recovery without interventions and with minimal production interruption.
 One of the recent improvements in production technologies which can remedy these problems having unique capabilities to do so is the Intelligent Well Completion (IWC) technology. In this paper the utilization of IWC to optimize oil recovery was evaluated. The use of a reservoir simulator, the Schlumberger ECLIPSE-100 simulator, was employed to model an intelligent well. Case study simulations were performed for an active bottom-water drive. Modeling of the Intelligent Well Inflow Control Devices (ICDs) and downhole sensors for the multilaterals was achieved using the Multi-Segment Well model.
 Optimal IWC technology combination for maximum hydrocarbon recovery and minimal water production was determined using the reactive control strategy (RCS) which indicated a drastic reduction of about 52.1% in water production with a slight drop of 1.5% in field oil efficiency (FOE). The simulation results obtained clearly showed that the utilization of intelligent well-ICDs in Production wells can significantly increase the cumulative oil production and reduce water production.

Intelligent Completion in Water-Injector Well Improves Field Development

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192850, “Improving Field Development Through Successful Installation of Intelligent Completion in a Water-Injection Well,” by Eglier Yanez, Mattheus Uijttenhout, Maher Zidan, Rail Salimov, Salem Al-Jaberi, Al Anoud Al-Shamsi, Amnah Al-Sereidi, Mohamed Mostafa Amer, Yousef Al-Hammadi, Abdullah Abdul-Halim, Giovani Caletti, Mustapha Adli, Yousif Hasan Al-Hammadi, and Fahad Mustafa Al-Hosani, ADNOC, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. The objectives were to improve reservoir management, reduce well-construction complexity, and achieve cost optimization. This paper covers the overall aspects of well performance in commingled injection mode. Introduction The offshore field was discovered in 1971 in the Arabian Gulf. On the basis of results from exploratory wells, three main reservoirs were proposed for further development (A, B, and C). The commercial phase of the field started successfully, with first oil in 2015 provided by the two first wellhead towers as part of the Phase I development plan. The completion design described in this paper is aligned with an optimized field-development plan (FDP) resulting from a study initiated in 2017. The main objectives of the study were integrating new acquired data to upgrade static and dynamic reservoir models to identify any opportunity for extra production and cost optimization. Early water breakthrough caused by the initial elected well pattern and the associated oil-producer-to-water-injector spacing is a significant risk. Therefore, accessibility and selectivity to control inflow are strongly recommended for the upper reservoir (A) to mitigate the breakthrough risk and secure long well life and maximize reserves. The initial dual completion, with two horizontal laterals targeting Reservoirs A and B, and a nonaccessible upper drain was removed, and a single controlled completion was placed. Field-Development Plan Pattern. The FDP consisted of two phases. Phase 1 consisted of an early production scheme from two wellhead towers and export of untreated crude to nearby facilities. This phase contained an intensive data-gathering program to reduce reservoir uncertainties and identify future risks and opportunities clearly. Phase 2 is the full field development, containing the bulk of the oil producers and water-injector (WI) wells drilled from new wellhead towers and newly installed offshore treatment facilities. The overall reservoir performance of Reservoir A was significantly better compared with the original basis of assumption. Consequently, the original line-drive development scheme between oil producers and WIs had to be revised in order to avoid early water breakthrough. As a response, the injector wells were placed outside the oil pool. The behavior of Reservoir B met expectations; for that reason, the line-drive well pattern was maintained in this reservoir.

A new autonomous inflow control device designed for a loose sand oil reservoir with bottom water

A downhole automatic inflow control device (AICD) can effectively delay the premature water breakthrough caused by unbalanced inflow profiles along the horizontal to improve production. However, solid particles seriously affect and restrict the normal operation of the AICD. In this paper, a new Cyclone Inflow Control Device (CICD) designed based on the principle of the cyclone to deal with the fine particles. The water control performance of the CICD was tested experimentally. The experimental results show that the pressure drop caused by the water flow was higher than the pressure drop of the oil flow at the same flow rate. The flow field distribution and the ability to deal with solids in the designed CICD are simulated via computational fluid dynamics (CFD). The effects of the structural parameters (inlet number, chamber slope, installation location) and fluid parameters (viscosity, flow rate and density) on the performance of the CICD were simulated. From the simulation results, we determined that: (1) Under the action of swirling flow, particles easily to accumulate in the ordinary disc swirling disk, and the funnel swirling disk can effectively discharge particles. (2) The pressure drop of the water flow is mainly produced in the swirl chamber, and the pressure drop of the oil flow mainly occurs at the inlet. (3) Adopting double inlets will not only ensure a higher pressure drop of the water flow, but will also reduce the pressure drop of the oil flow. (4) The larger the slope of the swirl chamber, the smaller the pressure drop that occurs, and the effect on the water flow is greater than the effect on the oil flow (5) The viscosity and flow rate have a greater influence on the performance of the CICD than the density.

Network-Constrained Production Optimization by Means of Multiple Shooting

Summary A methodology is proposed for the production optimization of oil reservoirs constrained by gathering systems. Because of differences in scale and simulation tools, production optimization involving oil reservoirs and gathering networks typically adopts standalone models for each domain. Although some reservoir simulators allow the modeling of inflow-control devices (ICDs) and deviated wells, the handling of gathering-network constraints is still limited. The disregard of such constraints might render unfeasible operational plans with respect to the gathering facilities, precluding their application in real-world fields. We propose using multiple shooting (MS) to handle the output constraints from the gathering network in a scalable way. MS allowed the handling of multiple output constraints because it splits the prediction horizon into several smaller intervals, enabling the use of decomposition and parallelization techniques. The novelty of this work lies in the coupling of reservoir and network models, and in the exploitation of the problem structure to cope with multiple network constraints. An explicit coupling of reservoir and network models is used to avoid the extra burden of converging the equations of the integrated system at every timestep. Instead, the inconsistencies between reservoir and network flows and pressures are modeled as constraints in the optimization formulation. Hence, all constraints regarding both reservoir and network equations are consistent at the convergence of the algorithm. The integrated-production-optimization problem is solved with a reduced sequential quadratic programming (SQP) (RSQP) algorithm, which is an efficient gradient-based optimization method. The MS ability to handle such constraints is assessed by a simulation analysis performed in a two-phase black-oil reservoir producing to a gathering network equipped with electrical submersible pumps (ESPs). The results showed that the method is suitable to handle complex and numerous network constraints. Because of the nonconvex nature of the control-optimization problem, a heuristic procedure was developed to obtain a feasible initial solution for the integrated-production system. Further, a case study compared long-term optimization with short-term practices, where the latter yielded a lower net present value (NPV), arguably because it could not anticipate early water-front arrivals.

Research and Field Application of Adaptive Inflow Control Technology

In view of conventional inflow control completion technique can not control water directly, the valid production period is relatively short, the control water effect become worse after bottom water breakthrough, easily lead to reservior second damage. Based on problem above, this paper presents an adaptive inflow control well completion technology, that uses adaptive inflow control device and precision sand filtering net control water screen, realizing to adjust the resistance of oil and water automaticlly, improving infow profile and oil well recovery, moreover, the adaptive inflow control well completion technology has the features of simple construction, high reliability and strong adaptability. Therefore, from the technological principle and characteristics, key implemental technology, the tool of adaptive inflow control device and screen, construction technology and other aspects of adaptive inflow control well completion technology, adaptive inflow control well completion technology were studied. The technology was applied in horizontal well completion in the B oilfield. After application, the oil production increased by 5 times, the oil production period of low water content was prolonged 400 days, a good effect of controlling water coning and increasing oil was acheved. The application suggests that adaptive infow control well completion technology can improve the effect of inflow control screen well completion that could be applied in the wells to increase the oil production.

Guest Editorial: Completion-System Reliability: Where Have We Been and Where Are We Going?

Guest editorial All completions systems should enable the safe and profitable extraction of reserves. Implicit in this statement is the presence of a stable, consistently performing completion system—in other words, a system with reliable hardware. This means that the completion system will enable production (or injection) with no system failures, over an expected span of time. This time span can range from 1 week for unconventional completions (fracturing plugs) to 30 years for deepwater completions. In all cases, reliable operations over some time t, or R(t), is the expectation. A goal for the completion system designer should be to maximize the useful life of the completion system (Fig. 1). In practice, this is achieved by minimizing what can be termed “infant mortality” and delaying the start of wear out. To maximize R(t), reliability of components, configurations, and processes must be maximized. Component Reliability Innovation leads to higher performance and optionality for most types of completion components. However, the development of new, innovative components also requires that their reliability be a design priority. Today, important drivers of component reliability are industry codes and standards (ICS). The American Petroleum Institute, the International Organization for Standardization, and NOR-SOK are ICS organizations with extensive portfolios of product standards. Each organization routinely updates its legacy standards and creates new ones. The Advanced Well Equipment Standards Group is a newer ICS organization that has recently completed a product standard for inflow control devices and is creating standards for encapsulated cable and degradable materials. Overall, the pace of standards creation is accelerating. A discussion of component reliability is incomplete without including the role of design for reliability (DFR) or design-assurance programs. These programs ensure that reliability receives due diligence in component development. The use of design failure mode effect analysis (DFMEA) is a cornerstone of an effective DFR program. These programs should be more prominent; this gap presents an opportunity for improvement. So, considering the question, “Where have we been?”, the answer is that the journey to date has been one of continuing improvements in the reliability of completion components. Configuration Reliability Is an Opportunity Of the technical paper abstracts I reviewed for the Completions feature in the April 2019 issue of JPT, 52% focus on completion configuration or optimization. Few abstracts focus on the ability of the completion configuration to perform reliably over long spans of time. Two critical aspects of configuration reliability are longevity and survivability.

Analytical, numerical and experimental study of gas coning on horizontal wells

Nowadays, new horizontal wells prone to experience gas cone problem usually have multiple production zones. These wells are equipped with inflow control devices (ICDs) or autonomous inflow control devices (AICDs) to mitigate the production of the undesired fluid. In the proposed study, we use analytical calculation, numerical simulations and experimental results to analyze different production strategies when using long horizontal wells in such reservoirs. By the end, we first identified numerical models to represent the dynamic behavior of a gas–oil interface. By validating them through an analytical solution, we used an active control strategy both to obtain and to analyze the associated flow rate for different positions of the interface in steady state from static equilibrium to the well neighborhood. The findings of this research reaffirm there is no strategy that overcomes the production with critical flow rate in steady state. However, the exact critical flow rate is a theoretical value, being hard to assess in the field. In this way, the main contribution of this study is to indicate for the case in consideration the usual production strategy of using multiple zones equipped with AICDs, since it has a cumulative production extremely close to the theoretical maximum and it represents a well-known technology for field applications.

Principles of rapid design of an inflow control device completion in homogeneous and heterogeneous reservoirs using type curves

This paper discusses the development and application of universal type-curves for the design of Advanced Well Completions (AWCs) equipped with passive (non-adjustable), flow control devices {a.k.a. Interval Control Devices (ICDs)}. This work provides an innovative, rapid approach to their design without the need for numerical simulators.AWCs equipped with ICDs aim to delay the early breakthrough of unwanted fluids in wells constructed close to a reservoir fluid contact. An uneven inflow profile due to reservoir permeability heterogeneity, multiple fluid contacts or an undulating well path needs to be managed. In addition, the Heel-to Toe effect (HTE) by frictional pressure loss due to fluid flow along the length of the completion interval also promotes a non-uniform inflow profile.The main AWC design challenge is to balance the trade-off between loss in well productivity from the added flow restrictions and the benefit of an improved inflow profile. This paper reviews the development of the analytical modelling of the inflow performance of horizontal wells with ICD completions, It presents new semi-analytical, mathematical models describing the ability of AWCs to mitigate production problems created by (reservoir) permeability heterogeneity and the (in-well) HTE. New dimensionless numbers allow the development of universal type-curves (TCs) for AWC design. The new workflow is illustrated for several case studies and the results validated by their good agreement with calculations made with the standard “well-reservoir” numerical simulator employed by engineers for this task.This novel approach for rapid analysis of the implications of well log data, such as that obtained shortly before the beginning the installation of the well completion, is the latest addition to the well completion engineering toolbox.

Simulation of the water controlling ability of an adaptive inflow control device

Traditional adaptive inflow control device (AICD) has low water control efficiency. Based on adaptive inflow control device, numerical simulation method is used to analyze the internal flow of the device. Influence of relevant design parameters on its water control capacity is studied. Internal structure of AICD is optimized to change internal flow and the flow path of oil flow in the restrictor. Purpose of controlling the flow of oil by using different viscosities of two flow states is achieved. Results show that setting the baffle to distinguish the annular passage and control chamber can improve pressure drop of water flow. The direction and number of flow channels have significant influence on AICD water control ability. Optimizing the shape of flow channel can change entrance speed and entrance angle, improving the water control capacity of inflow controlling device. The AICD achieves the optimal control capacity when it adopts the one transitional flow channel with 45°A angle.

Structural Parameter Optimization and Performance Analysis of Autonomous Inflow Control Device

The Autonomous Inflow Control Device (AICD) adjusts the inflow of the horizontal wellbore by adding additional resistance to the fluid, thereby prolonging the water seepage time and enhancing oil recovery. The performance of AICD mainly depends on structural parameters. The computational fluid dynamics software is used to analyze the influence of structural parameters on the performance of AICD. The results show that the diameter of the variable diameter section, the diameter of the restrictor and the diameter of the outlet are the main factors affecting the performance of the inflow control device. The fluid parameter sensitivity simulation results show that the oil phase viscosity and water content have a great influence on the performance of AICD, while the influence of oil phase density on the performance of the device is negligible; the pressure drop under the pure water condition of this type of AICD is more than twice that of pure oil condition, so it has better water control ability.

Predicting Performance of High Deliverability Horizontal Gas Wells and Control of Water Cresting in Tertiary Sands East Africa

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Predicting Performance Of High Deliverability Horizontal Gas Wells And Control Of Water Cresting In Tertiary Sands East Africa

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Оценка эффективности применения устройств контроля притока в условиях залежей сверхвязкой нефти ПАО «Татнефть»

Оценка эффективности применения устройств контроля притока в условиях залежей сверхвязкой нефти ПАО «Татнефть»

Combining Passive and Autonomous Inflow-Control Devices in a Trilateral Horizontal Well in the Alvheim Field

Summary In this paper we describe the analysis, test, and design work to deliver an optimal lower completion for a trilateral well by integrating passive and autonomous inflow-control devices (ICDs) (AICDs) at the Alvheim Field offshore Norway. In 2015, both passive ICDs and AICDs were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing demonstrated that the AICD chokes gas more efficiently than the passive ICD. The experimental results enabled correct modeling of AICDs in both the reservoir-simulation model and the simpler steady-state inflow model. The following lower-completion strategy was established for the new well: Where the well was close to the overlying gas cap, AICDs should be used, whereas passive ICDs with variable strength were to be used elsewhere to optimize the inflow. During the drilling phase, the steady-state model was updated with the as-drilled information; the lower-completion design for each branch focused on obtaining what was estimated to be an optimal inflow depending on the oil volume per drainage area. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers. The lower completion covered 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the cleanup and the inflow profile along the well. The well started producing in May 2016 and a successful cleanup was confirmed by oil-tracer responses. In August 2016, a restart-tracer-sampling campaign was performed after a 12-day shut-in, and this formed the basis for a “chemical production log.” The tracer-based inflow interpretation was compared quantitatively with the model-predicted inflow and qualitatively to the tracer responses seen during the cleanup. The comparison confirmed that the lower completion works as initially planned. The interpretation further indicated that the upper zone has a lower degree of pressure support than the lower zone, and that the larger shaly sections have creeped/collapsed and act as packers. The well has exceeded predrill production expectations, with an average oil rate of 3375 std m3/d (21,240 STB/D) during the first production year. A large part of exceeding the predrill expectations is attributed to the lower-completion design, where the focus has been to optimize such that the whole well contributes, from the heel to all toes.

A new method to calculate sweep efficiency of horizontal wells in heterogeneous reservoir

This paper discusses the development challenges of an offshore fluvial oil reservoir with horizontal wells. In highly productive sandstone reservoirs, horizontal wells suffer from uneven flow profile and subsequent premature coning effects because of sand heterogeneity and heel to toe effect. Moreover, excessively increasing the production rate or horizontal well length can increase the risk of limited sweep efficiency, resulting in remaining oil in the toe or poor sand with low permeability. First, we analyze the characters of fluvial oil reservoir focusing on sand architecture and heterogeneity. Second, the sweep efficiency was calculated by the production data. Finally, we optimize inflow control device (ICD) for several wells and compare the response of ICD wells with conventional screen completion wells.

Technology Focus: Production and Facilities (December 2018)

Technology Focus Creativity and innovation have long characterized production and facilities, and this year is no exception. Much of the work reported this past year was conducted during the recent period of low oil prices. The economic challenges of the oil industry clearly have provided a strong stimulus for even more creativity and innovation. The use of big data and analytics appeared in a number of papers with an emphasis on the use of artificial intelligence (AI) for building databases used to monitor the health of equipment and structure risk-based-inspection (RBI) strategies. Monitoring data inputs from thousands of sensors (paper OTC 28990) allows an AI application to predict an impending failure and notify operators by text or email when the incipient problem is detected so that proactive maintenance can be scheduled to avoid an unplanned shutdown or catastrophic failure. This strategy is being successfully applied to compressors but no doubt will be used to monitor other high-cost, critical service equipment as well (paper SPE 188803). Progress continues on the design and application of inflow-control devices (ICDs). Introduced only a few years ago, these devices are still in a rapid development stage for both design and application. Now, ICDs are applied successfully to improve the fluid-injection patterns for both steamfloods and waterfloods, the latter being described as a successful field application (paper SPE 189824). For steamfloods, passive and autonomous ICD designs were evaluated and their performance modeled using computational fluid dynamics (paper SPE 189721). The integration of subsurface modeling and surface-facility design by the development of a data-driven stochastic work flow (paper SPE 187462) demonstrated a means to reduce both subsurface and facility costs by reducing the biases that inevitably come into play during the generation of a field-development plan. Other innovative work was reported on field optimization, the prediction of asphaltene precipitation, and the integration of RBI with vibration-induced fatigue failure of installed piping systems. Interesting work not discussed here includes evaluating corrosion under severe conditions and the development of an oil-droplet-coalescing pump for use in water treatment. Recommended additional reading at OnePetro: www.onepetro.org. SPE 188803 Machines Performance Algorithmic Modeling for Anticipating Machines Health Using Real-Time Condition-Monitoring Data by W. Almadhoun, ADMA-OPCO, et al. SPE 189721 Evaluation of Inflow-Control-Device Performance Using Computational Fluid Dynamics by M. Miersma, University of Alberta, et al. SPE 187256 Production Optimization of Shenzi Field in the Deepwater Gulf of Mexico by P. Ashton, BHP, et al. SPE 190149 A Diagnostic Approach To Predict Asphaltene Deposition in Reservoir and Wellbore by Davud Davudov, University of Oklahoma, et al. OTC 28352 Integrating an RBI Approach for Vibration-Induced Fatigue Into a Mechanical-Integrity Program by Paul Crowther, Wood, et al.

Results of the research project AssiSt

This article gives an overview of the results of the wind energy research project AssiSt. Results of the four work packages include flow in complex terrain, wind energy converters (WEC) in complex terrain subject to atmospheric inflow, laminar-turbulent transition, generator cooling, hub aerodynamics, and passive flow control devices. Four different flow solvers (PALM, FLOWer, THETA, OpenFOAM) are in use during the course of the project depending on the corresponding problem requiring specific solver features. Key achievements of the project are the coupling of atmospheric LES (PALM) and URANS simulations of the complete WEC (FLOWer as well as THETA) in order to impose the external turbulent flow fields to the inflow of the WEC for physics resolved load simulations, numerical replication of complex flows over blades with vortex generators using OpenFOAM and efficiency-augmented pressure loss simulations on very complex industrial geometries of ENERCON’s direct drive WEC generators for precise cooling analyses. Industrial validity of all methods, model and process developments were key objectives of this research project.

Reservoir simulator-friendly model of fluid-selective, downhole flow control completion performance

Wells with long production/injection intervals (e.g. horizontal or multi-lateral wells) can be equipped with flow control completion (FCC), which allows zonal control of in/out-flow and is a proven method to improve sweep efficiency, extend well life, and reduce the production volumes of unwanted fluids. The application of FCC is essential to development of many oil fields with complex geology, uncertain reservoir description, close to contact completions or unfavourable mobility ratio.FCC technology keeps developing, for instance the recently introduced Autonomous Inflow Control Device (AICD) or Valve (AICV) strongly reacts to unwanted phases (gas or water) restricting their flow in-situ, which improves recovery as well as reduces the volume of unwanted fluids and the production uncertainty.This paper presents a novel approach to incorporate into a reservoir simulator the flow performance of a downhole flow control completion equipped with flow control devices discriminating flowing fluids, e.g. reacting to water/gas flow distinctly differently than to oil. AICDs and AICVs are examples of such devices. The novel approach is verified by numerical simulation and is further compared against the traditional modelling approach on a reservoir model.In the case of oil and water/gas flow, the multi-modal response of the device is new in the industry, and the reservoir simulators are not yet up-to-date to model such performance. The segregated flow in the annulus results in the device(s) reacting sequentially to either oil or water/gas, as opposed to the “homogeneous flow” modelling approach that is traditionally assumed in reservoir simulators. Capturing the sequential reaction of the device to either oil or water/gas in a reservoir simulator is challenging. The equations derived here solve this problem, and offer a more accurate way of modelling autonomous flow control completion performance in a commercial reservoir simulator.This work is an important contribution to the advanced well completion technology modelling and evaluation. This technology is likely to define the future of advanced wells.