Modelling and Optimisation of Flow Control Valves Case Study From the Greater Burgan Field, Kuwait

2020 ◽  
Author(s):  
Mustafa Al-Hussaini ◽  
Hamad Al-Kandari ◽  
Ravi Kurma ◽  
Kishore Jyoti Burman ◽  
Wuroud M. Al-Fadhli ◽  
...  
Keyword(s):  
Flow Control ◽  
Net Present Value ◽  
Dynamic Modelling ◽  
Oil Production ◽  
Production Performance ◽  
Capital Outlay ◽  
Water Production ◽  
Control Valves ◽  
Sector Model ◽  
Well Completion

Abstract This paper describes a dynamic modelling and optimization study to investigate the viability of deploying intelligent completions for well management in a mature oilfield in order to mitigate the challenges of increasing water cut and rapid diminishing of surface locations for new wells across the Greater Burgan field. Reservoir simulation is used to assess the potential benefits of installing Flow Control Valves (FCVs) in a candidate well, to control production from multiple reservoir zones. A representative sector model is defined around the candidate well, to include surrounding wells that could influence its flow behaviour. Reservoir properties are extracted from a fine-scale geological realization and updated using current well logs. Sensitivity studies are performed to determine the appropriate size and grid design for simulation. The well is planned to be completed across six producing reservoir zones with a single tubing and an Electrical Submersible Pump (ESP). In the optimization strategy, the FCV aperture openings are adjusted over the lifetime of the well, to maximize the Net Present Value, while meeting operational and strategic constraints. The robustness of the forecast outcomes are highly dependent on the quality of reservoir characterization. A sector model large enough to represent the effects of reservoir heterogeneities and interference from other wells, was used. The efficient optimization workflows used here can be generalized for similar analyses of other wells and other fields. The optimized results demonstrate that installation of FCVs can help to meet the simultaneous objectives of boosting oil production while reducing water production. This is achieved by choking back the deeper high-water production zones to accelerate oil production from the upper high oil saturation zones, while also targeting offtake to induce the shallower low-pressure zone to deliver more. The large initial capital outlay, comprising the equipment and service cost of the FCV installation is fully offset within the first year of production, post installation. This study highlights the significant upside benefits for the management of complex brown fields such as the Greater Burgan by adopting smart well completion strategy. Improving well production performance, and supporting multi-zone completions, should also enable reduction of well counts for fields with existing high well density and lack of surface space to accommodate many new dispersed wells.

scholarly journals End-Point Model for Optimization of Multilateral Well Placement in Hydrocarbon Field Developments

Energies ◽  
2020 ◽  
Vol 13 (15) ◽  
pp. 3926
Author(s):  
Damian Janiga ◽  
Daniel Podsobiński ◽  
Paweł Wojnarowski ◽  
Jerzy Stopa
Keyword(s):  
Production Rate ◽  
Net Present Value ◽  
Capital Expenditure ◽  
Reservoir Management ◽  
Oil Production ◽  
Management Plan ◽  
Water Production ◽  
Reservoir Water ◽  
Well Placement ◽  
End Point

Drilling cost is one of the most critical aspects in the reservoir management plan. Costs may exceed a million dollars; thus, optimal designing of the well trajectory in the reservoir and completion are essential. The implementation of a multilateral well (MLW) in reservoir management has great potential to optimize oil production. The object of this study is to develop an integrated workflow of end-point multilateral well placement optimization integrated with the reservoir simulator supported by artificial intelligence (AI) methods. The paper covers various types of MLW construction, including: horizontal, bi-, tri-, and quad-lateral wells. For quad-lateral wells, the capital expenditure is highest; nevertheless, acceleration of oil production affects the project’s NPV (net present value), indicating the type of well that is most promising to implement in the reservoir. Tri- and quad-lateral wells can operate for 12.1 and 9.8 years with a constant production rate. The decreasing hydrocarbon production rate is affected by reservoir pressure and the reservoir water production rate. Other well design patterns can accelerate water production. The well’s optimal trajectory was evaluated by the genetic algorithm (GA) and particle swarm optimization (PSO). The major difference between the GA and PSO optimization runs is visible with respect to water production and is related to the modification of one well branch trajectory in a reservoir. The proposed methodology has the advantage of easy implementation in a closed-loop optimization system coupled with numerical reservoir simulation. The paper covers the solution background, an implementation example, and the model limitations.

scholarly journals OPTIMIZATION OF OPERATING FRACTURING PARAMETERS FOR IMPROVING OIL PRODUCTION IN LOWER OLIGOCENE E RESERVOIR USING RESPONSE SURFACE METHOD, OFFSHORE VIETNAM: A CASE STUDY

2019 ◽  
Vol 18 (4) ◽  
pp. 422-432
Author(s):  
Truong Nguyen Huu
Keyword(s):  
Net Present Value ◽  
Oil Production ◽  
Geological Structure ◽  
Injection Rate ◽  
Production Performance ◽  
Injection Time ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Fractured Well

In the recent days, hydraulic fracturing technique has been widely used to improve oil production with different reservoir characteristics such as low or high formation permeability, low or high formation porosity, formation damage. However, previous research did not mention the optimization for fracturing parameters including the injection rate, injection time, and leak-off coefficient to stimulate the Oligocene E reservoir, which is based on optimum oil production performance at which maximum net present value has been achieved. The problems in the Oligocene reservoir are too low production rate due to high reservoir depth, high closure pressure up to 7,700 psi, low reservoir permeability, low porosity and geological structure with heterogeneous reservoir, high temperature, resulting in low conductivity. To deal with these problems, fracturing technique is the best choice to stimulate this reservoir. The study focuses on optimizing fracturing parameters by applying the CCD and RSM  by which economic production performance has been maximized at 119 $ in 10 years. The optimum fracturing parameters have been found as injection rate of 47 bpm, injection time of 119 minutes and leak-off coefficient of 0.003 ft/min0.5 in 50 pounds per thousand gallons of polymer (HPG). The optimal fracture geometry has been obtained with the fracture half-length of 1,449.44 ft and fracture width of 0.567 in. The rest of experimental laboratory is to measure fracture conductivity at 3,400 mD.ft in terms of proppant fracture concentration of 1.78 lb/ft2 and high closure pressure of 7700 psi. The post fractured well shows an increase in oil productivity of 7.5 folds.

A Geoengineering Approach to Maximum Reservoir Contact Wells Design: Case Study in a Carbonate Reservoir Under Water and Miscible Gas Injection

2021 ◽  
Author(s):  
Alfredo Freites ◽  
Victor Segura ◽  
Muhammad Muneeb
Keyword(s):  
Gas Injection ◽  
Oil Production ◽  
Carbonate Reservoir ◽  
Production Performance ◽  
Pressure Drops ◽  
Well Completion ◽  
Entry Points ◽  
Miscible Gas Injection ◽  
Well Completions

Abstract Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.

Autonomous Inflow Control Device Pilot Application for Extra Heavy Oil Field

2018 ◽  
Author(s):  
Mahmoud Abdel Rafea ◽  
Cristhian Criado
Keyword(s):  
Heavy Oil ◽  
Horizontal Well ◽  
Control Device ◽  
Oil Field ◽  
Water Production ◽  
Fine Grid ◽  
Sector Model ◽  
Well Completion ◽  
Horizontal Length ◽  
Inflow Control Device

Autonomous Inflow Control Device (AICD) completion was successfully designed and applied in a horizontal well drilled in a deep reservoir in an extra heavy oil field located in South America where the average total depth of the targeted reservoir is around ten thousands feet and the in-situ viscosity is 600 cps while API Gravity is ranged between 8.5–9.5. Due to geological and petro-physical features in this area which turns into permeability variations and thick transition zone across the reservoir, a horizontal well of 2500 feet length was drilled and completed with a standalone screen along with Autonomous Inflow Control Device (AICD) to avoid sand production and delay water production. The initial design for the AICD considered the variation of permeability, rock quality, pressure differential across the horizontal length including the operational factors. Accordingly, multiple scenarios using reservoir simulation built-in model (Petrel-RE) and Netool for ICD selection, design and placement where the geological properties of the model were updated based on the run NMR and Caliper logs while geo-steering the well. Also, a fine grid sector model was generated to assess optimum well completion design. The AICD completion was successfully deployed and resulted in extending the well life by delaying water production and it is expected to get its ultimate benefit whenever starting the implementation of a water flood project near that producer well.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

Development and Execution of Heritage Petroleum Company Limited’s First Offshore Workover Campaign - A Case History of Successful Implementation of Performance Management

2021 ◽  
Author(s):  
Shazim Mohammed ◽  
Dale Persad ◽  
Kirk Baksh
Keyword(s):  
Trinidad And Tobago ◽  
Performance Management ◽  
Net Present Value ◽  
Oil And Gas ◽  
Selection Process ◽  
Public Procurement ◽  
Dynamic Modelling ◽  
Successful Implementation ◽  
Procurement Process ◽  
Petroleum Company

Abstract Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework. The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin. The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions. The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign. The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.

Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

2021 ◽  
Author(s):  
Pawan Agrawal ◽  
Sharifa Yousif ◽  
Ahmed Shokry ◽  
Talha Saqib ◽  
Osama Keshtta ◽  
...  
Keyword(s):  
Continuous Production ◽  
Oil Production ◽  
Gas Production ◽  
Oil Field ◽  
Production Performance ◽  
Fluid Distribution ◽  
Flow Profile ◽  
Horizontal Drain ◽  
Control Devices

Abstract In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

Advanced Multi-Disciplinary Simulation Workflow for Well Placement, Hydraulic Fracturing and Production Optimization Applied to the Diyab Unconventional Play in Onshore UAE

2021 ◽  
Author(s):  
Hamid Pourpak ◽  
Samuel Taubert ◽  
Marios Theodorakopoulos ◽  
Arnaud Lefebvre-Prudencio ◽  
Chay Pointer ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
United Arab Emirates ◽  
Reservoir Characterization ◽  
Horizontal Wells ◽  
Production Optimization ◽  
Production Performance ◽  
Well Placement ◽  
Fully Integrated ◽  
Sector Model ◽  
The Impact

Abstract The Diyab play is an emerging unconventional play in the Middle East. Up to date, reservoir characterization assessments have proved adequate productivity of the play in the United Arab Emirates (UAE). In this paper, an advanced simulation and modeling workflow is presented, which was applied on selected wells located on an appraisal area, by integrating geological, geomechanical, and hydraulic fracturing data. Results will be used to optimize future well landing points, well spacing and completion designs, allowing to enhance the Stimulated Rock Volume (SRV) and its consequent production. A 3D static model was built, by propagating across the appraisal area, all subsurface static properties from core-calibrated petrophysical and geomechanical logs which originate from vertical pilot wells. In addition, a Discrete Fracture Network (DFN) derived from numerous image logs was imported in the model. Afterwards, completion data from one multi-stage hydraulically fracked horizontal well was integrated into the sector model. Simulations of hydraulic fracturing were performed and the sector model was calibrated to the real hydraulic fracturing data. Different scenarios for the fracture height were tested considering uncertainties related to the fracture barriers. This has allowed for a better understanding of the fracture propagation and SRV creation in the reservoir at the main target. In the last step, production resulting from the SRV was simulated and calibrated to the field data. In the end, the calibrated parameters were applied to the newly drilled nearby horizontal wells in the same area, while they were hydraulically fractured with different completion designs and the simulated SRVs of the new wells were then compared with the one calculated on the previous well. Applying a fully-integrated geology, geomechanics, completion and production workflow has helped us to understand the impact of geology, natural fractures, rock mechanical properties and stress regimes in the SRV geometry for the unconventional Diyab play. This work also highlights the importance of data acquisition, reservoir characterization and of SRV simulation calibration processes. This fully integrated workflow will allow for an optimized completion strategy, well landing and spacing for the future horizontal wells. A fully multi-disciplinary simulation workflow was applied to the Diyab unconventional play in onshore UAE. This workflow illustrated the most important parameters impacting the SRV creation and production in the Diyab formation for he studied area. Multiple simulation scenarios and calibration runs showed how sensitive the SRV can be to different parameters and how well placement and fracture jobs can be possibly improved to enhance the SRV creation and ultimately the production performance.

Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Miracle Imwonsa Osatemple ◽  
Abdulwahab Giwa
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Oil Production ◽  
Base Case ◽  
Present Value ◽  
Sweep Efficiency ◽  
Recovery Method ◽  
Solution Approach ◽  
Hydrocarbon Reservoir

Abstract There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.

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