Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

2021 ◽  
Author(s):  
Nasser AlAskari ◽  
Muhamad Zaki ◽  
Ahmed AlJanahi ◽  
Hamed AlGhadhban ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Production Performance ◽  
Shallow Depth ◽  
Production Rates ◽  
Field Development ◽  
Artificial Lift ◽  
Geological Conditions ◽  
Fracture Fluid ◽  
Reservoir Potential ◽  
Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

scholarly journals Design and Economic Evaluation of the ESP and Gas Lift on the Dead Oil Well

2018 ◽  
Vol 8 (6) ◽  
Author(s):  
Imran A. Hullio ◽  
Sarfraz A. Jokhio ◽  
Khalil Rehman Memon ◽  
Sohail Nawab ◽  
Khair Jan Baloch
Keyword(s):  
Capital Budgeting ◽  
Production Performance ◽  
Oil Well ◽  
Production Rates ◽  
Production Forecast ◽  
Artificial Lift ◽  
Operating Expenditures ◽  
Water Cut ◽  
Gas Lift ◽  
Design And Production

Owing to the increasing water cut and decreasing in reservoir pressure of the well, the oil production of the well has seized and the well has become dead. This research study evaluates the implementation of the artificial lift methods ESP and Gas Lift- economically and technically on the well by using the production performance software (PROSPER) and economical yardsticks (NPV and ROI). The theory, design, production forecast, capital and operating expenditures of the electric submersible pump and gas lift are discussed for the appropriate selection of any of two options. The PROSPER software is used as the simulation tool for the design and production forecasting of the ESP and Gas Lift based. The ESP and Gas Lift methods have been simulated for the design and production forecast by entering the reservoir and completion inputs in the software. Subsequently, the software has been simulated to run on different sensitivities of the variables such as water cut, wellhead pressure setting depth, operating frequency and gas injection rates to check the production rates at different scenarios. Having performed the production performance simulation on the selected artificial lift methods, the methods have been investigated by capital budget-ing. In capital budgeting, the capital and operating expenditures of both lift methods were evaluated by determining their discounted value (NPV) and re-turn on investment (ROI). The prime objective of the research is to accomplish maximum production rates and profitability by selecting the most appropriate artificial lift method for the well; as a consequence it is concluded that the suitable artificial lift method for a well can be selected by applying the simulation and economical schemes.

Low Well Cost: Effective Cost Optimisation for Marginal Green Field Development Using Fit-for-Purpose Well Design

2021 ◽  
Author(s):  
Thivyashini Thamilyanan ◽  
Hasmizah Bakar ◽  
Irzee Zawawi ◽  
Siti Aishah Mohd Hatta
Keyword(s):  
Cost Effective ◽  
Second Phase ◽  
Sand Production ◽  
Field Development ◽  
Well Completion ◽  
Artificial Lift ◽  
Sand Control ◽  
Fit For Purpose ◽  
Reservoir Connectivity ◽  
Gas Lift

Abstract During the low oil price era, the ability to deliver a small business investment yet high monetary gains was the epitome of success. A marginal field with its recent success of appraisal drilling which tested 3000bopd will add monetary value if it is commercialized as early as possible. However, given its marginal Stock Tank Oil Initially in Place (STOIIP), the plan to develop this field become a real challenge to the team to find a fit-for-purpose investment to maximize the project value. Luxuries such as sand control, artificial lift and frequent well intervention need to be considered for the most cost-effective measures throughout the life of field ‘Xion’. During field development study, several development strategies were proposed to overcome the given challenges such as uncertainty of reservoir connectivity, no gas lift supply, limited footprint to cater surface equipment and potential sand production. Oriented perforation, Insitu Gas Lift (IGL), Pressure Downhole Gauge (PDG), Critical Drawdown Pressure (CDP) monitoring is among the approaches used to manage the field challenges will be discussed in this paper. Since there are only two wells required to develop this field, a minimum intervention well is the best option to improve the project economics. This paper will discuss the method chosen to optimize the well and completion strategy cost so that it can overcome the challenges mentioned above in the most cost-effective approach. Artificial lift will utilize the shallower gas reservoirs through IGL in comparison to conventional gas lift. Sand Production monitoring will utilize the PDG by monitoring the CDP. The perforation strategy will employ the oriented perforation to reduce the sand free drawdown limit compare to the full perforation strategy. The strategy to monitor production through PDG will also reduce the number of interventions to acquire pressure data in establishing reservoir connectivity for the second phase development through secondary recovery and reservoir pressure maintenance plan. This paper will also explain the innovative approaches adopted for this early monetization and fast track project which is only completed within 4 months. This paper will give merit to petroleum engineers and well completion engineers involved in the development of marginal fields.

An Overview of Surmont SAGD ESP Gas Handling Project to Mitigate Production Effects of NCG Co-Injection

2021 ◽  
Author(s):  
Kristian Nespor ◽  
Roger Walters ◽  
Curtis Goulet ◽  
Bryan Coates ◽  
Daine Studer
Keyword(s):  
Separation Efficiency ◽  
Production Capacity ◽  
Production Performance ◽  
Production Rates ◽  
Term Change ◽  
Before And After ◽  
Gas Separator ◽  
Term Performance ◽  
Production Effects

Abstract NCG (Non-Condensable Gas) co-injection with steam has been in operation at Surmont SAGD field since 2017. After a significant number of operational attempts to mitigate ESP no flow events (deadheading) suspected to be instigated by increased production of gas (typical SAGD GOR 5-10 m3/m3) a strategy was developed to focus on completion adjustments to the ESP on candidate SAGD producers. These changes were completed in late 2019 to help reduce the loss of production, which could impact viability of NCG co-injection at Surmont. Three separate completion adjustments were made: an inverted shroud installation, a larger OD pump with a gas separator, and lowering of an ESP to the lowest possible TVD. A comparison of the production and operational performance before and after each completion adjustment was completed. In-depth design reviews between CPC and the equipment vendor were done to ensure maximum chance of positive benefit. The inverted shroud installation was expected to improve gas separation efficiency, leading to a reduction in the frequency of No Flow Events (NFEs), which were impacting production rates. The shrouded ESP performance on the first candidate well showed no NFEs with a significant increase in production rates compared to the baseline before the completion adjustment. The larger OD pump with gas separator install was also expected to reduce or completely prevent NFEs. the results were also positive, with an increase in production and no further NFEs recorded. Lowering of a third ESP to a point as close as possible to the liner hanger did not achieve any long-term change in production performance. With the success of the inverted shroud, a second installation was completed on the third well where the ESP was being lowered. A production increase and prevention of NFEs were documented like the first shroud installation, confirming the benefit of the shrouded ESP design. The completion changes confirmed that suitable adjustments to mitigate the effects of NCG injection are possible, with further development on design required to optimize for production capacity and long-term performance. With the results seen so far, further installations will be completed in the future on appropriate candidates to continue to mitigate the effect on ESPs of produced NCG volumes.

Productive capacity evaluation of perforated filter on long-term developed fields

2020 ◽  
pp. 30-34
Author(s):  
I.Z. Ahmadov ◽  
◽  
S.E. Tagiyeva ◽  
F.N. Hagverdiyev ◽  
H.G. Huseinov ◽  
...  
Keyword(s):  
Late Stage ◽  
Production Performance ◽  
Productive Capacity ◽  
Flow Rates ◽  
Field Development ◽  
Stage Of Development ◽  
Capacity Evaluation ◽  
Actual Field ◽  
Water Cut

The paper presents the results of studies on the qualitative and quantitative effect of filter capacity on the production performance of wells at the late stage of field development. Based on the actual field data, the distribution of filter capacity values by wells, as well as the dependence of oil, water flow rates and water cut on filter power was analyzed. Via a software program the equations describing these relationships were developed. The studies showed a decrease in oil production rate and increase in water cut with filter power. The limiting capacity of the filter, to which the operation is carried out with the most optimal flow rates and water cut, is specified. It is indicated that the main reason delaying the growth of production is the intensive flooding of formations, which is characteristic for fields at the late stage of development.

Artificial Lift Project in Bekapai Field, A Comprehensive and Challenging Selection Process for Mature Offshore Field

2021 ◽  
Keyword(s):  
Selection Process ◽  
Production Model ◽  
Screening Process ◽  
Artificial Lift ◽  
Natural Flow ◽  
Term Evaluation ◽  
Offshore Field ◽  
The Impact ◽  
Gas Lift

Bekapai field was discovered in 1972, production commenced in July 1974 and the peak production was achieved in June 1978. This paper presents a challenging and comprehensive artificial lift selection process in mature offshore field, after produced by natural flow for more than 40 years. The screening process is a very important step for the long term profitability of the field. During the initial screening process, several aspects of subsurface characteristic and surface limitation have been studied to find the feasible artificial lift method. It shows that electric submersible pump (ESP) has several critical limitations to be implemented in this field. A long term evaluation then performed to evaluate the impact of any subsurface and surface variations on the performance of artificial lift. Integrated production model was used to predict the long term performance and ultimate recovery, either naturally or using gas lift and ESP. This model is a numerical simulation to describe the reservoir behavior, production system and find the optimum production strategy by integrating the reservoir models, well models and the surface network model. Impact of any variations in reservoir, well condition and surface parameters are evaluated until end of life or economical limit of this field. Based on this evaluation, gas lift and ESP have higher recovery factor than natural flow condition. The production cumulative is expected increase by more than 40% for the next 10 years. In this simulation also observed that gas oil ratio (GOR) is increasing by time, it’s a critical limitation for ESP. By performing long term evaluation and economical evaluation, it’s confirmed that gas lift is the most feasible artificial lift method for Bekapai field. This comprehensive selection process also ensures the long term profitability of the field.

First Digital Intelligent Artificial Lift Production Optimization Technology in UAE Dual-String Gas Lift Well - Business Case and Implementation Plan

2019 ◽  
Author(s):  
Ahmed Alshmakhy ◽  
Khadija Al Daghar ◽  
Sameer Punnapala ◽  
Shamma AlShehhi ◽  
Abdel Ben Amara ◽  
...  
Keyword(s):  
Business Case ◽  
Production Optimization ◽  
Implementation Plan ◽  
Artificial Lift ◽  
Gas Lift

scholarly journals Geomechanical justification of security measures in the development of the South Khingan deposit of manganese ore

2018 ◽  
Vol 56 ◽  
pp. 02014
Author(s):  
Maksim Rasskazov ◽  
Marina Potapchuk ◽  
Gennady Kursakin ◽  
Denis Tsoy
Keyword(s):  
Physical And Mechanical Properties ◽  
Rock Massif ◽  
Manganese Ore ◽  
Security Measures ◽  
The South ◽  
Rockburst Hazard ◽  
Field Development ◽  
Stage Of Development ◽  
Geological Conditions ◽  
Numerical Simulation Methods

The paper presents the results of geomechanical studies on the assessment of the potential rockburst hazard of the rock massif of the South Khingan deposit of manganese ore at the stage of development. Geodynamic zoning has been performed, mining and technical, mining and geological conditions of field development have been studied, and parameters of physical and mechanical properties of enclosing rocks and ores have been determined. Numerical simulation methods have been used to estimate the stress state of a rock massif at various stages of the deposit development. The tendency of the lower part of the South Khingan deposit to rockburst has been established. The complex of effective organizational and technical security measures has been substantiated in the development of this field.

Construction and operation of batching plants in difficult geological conditions of Upper Kama potash mines

2021 ◽  
pp. 51-56
Author(s):  
V. N. Aptukov ◽  
V. V. Tarasov ◽  
V. S. Pestrikova ◽  
O. V. Ivanov
Keyword(s):  
Crack Opening ◽  
Concrete Lining ◽  
Salt Deposit ◽  
Mine Shaft ◽  
Deformation And Fracture ◽  
Geological Conditions ◽  
Negative Impacts ◽  
Long Term Experience ◽  
Term Maintenance

Scenarios of the component arrangement of batching plants in the system of a vertical mine shaft are discussed. The features of operation of batching plants in vertical shafts of potash mines are identified. The actual recorded damages generated in the lining of batching plants in the course of their longterm operation in potash mines are described. The geomechanical researches aimed to determine vertical convergence in batching rooms of mine shafts, as well as for monitoring of crack opening and displacements in sidewalls in the batching chambers are presented. The major results of the full-scale geomechanical observations are reported, and the main causes of fractures in concrete and reinforced concrete lining at junctures of shafts and batching rooms and shaft bins are identified. The set of the engineering solutions implemented for the protection of lining in batching facilities during construction of mine shafts is described, and its efficiency is evaluated. The mathematical modeling is carried out to estimate various negative impacts on deformation and fracture of concrete lining in shafts with regard to the time factor. From the modeling results, the dominant cause of concrete lining damage in batching chambers and in mine shaft is found. Based on the accomplished research results and actual long-term experience of operation of mine shafts, the most favorable factors are determined for the best design choices in construction and long-term maintenance-free operation of batching plants in potash mines of the Upper Kama Potash–Magnesium Salt Deposit.

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

Sign in / Sign up

Export Citation Format

Share Document