First Successful Proppant Frac in a Water Injection Field Strategy, West Qurna-1, South Iraq

2022 ◽  
Author(s):  
Erfan Mustafa Al lawe ◽  
Adnan Humaidan ◽  
Afolabi Amodu ◽  
Mike Parker ◽  
Oscar Alvarado ◽  
...  
Keyword(s):  
Water Injection ◽  
Injection Rate ◽  
Fracture Model ◽  
Productivity Index ◽  
Base Line ◽  
Reservoir Pressure ◽  
Injection Strategy ◽  
Injection Test ◽  
Step Rate ◽  
Step Down

Abstract Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability. The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate. A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume. A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and water injection field strategy, represents a building platform for further field development optimization plans in Southern Iraq.

The Perspective of Novel Chemical Tracer Technology in Reservoir Surveillance and Hydrodynamic Modelling for More Efficient Hydrocarbon Recovery

2021 ◽  
Author(s):  
Nadir Husein ◽  
Evgeny Aleksandrovich Malyavko ◽  
Ruslan Rashidovich Gazizov ◽  
Anton Vitalyevich Buyanov ◽  
Aleksey Aleksandrovich Romanov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Continuous Production ◽  
Economic Effect ◽  
Water Injection ◽  
Injection Rate ◽  
Reservoir Pressure ◽  
Entire Area ◽  
Field Development ◽  
Oil Companies ◽  
Maintenance System

Abstract Today, efficient field development cannot be managed without proper surveillance providing oil companies with important geological and engineering information for prompt decision-making. Once continuous production is achieved, it is necessary to maintain a consistently high level of oil recovery. As a rule, a reservoir pressure maintenance system is extensively implemented for this purpose over the entire area because of decreasing reservoir pressure. At the same time, it is important to adjust the water injection to timely prevent water cut increasing in production wells, while maintaining efficient reservoir pressure compensation across the field. That is why it is necessary to have a relevant inter-well hydrodynamic model as well as to quantify the water injection rate. There are many ways to analyse the efficiency of the reservoir pressure maintenance system, but not all of them yield a positive, and most importantly, a reliable result. It is crucial that extensive zonal production surveillance efforts generate a significant economic effect and the information obtained helps boost oil production. Thus, the main objective of this paper is to identify a method and conduct an effective study to establish the degree of reservoir connectivity and quantify the inter-well parameters of a low permeability tested field.

Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage With Potential Application to Offshore Trinidad

SPE Journal ◽  
2013 ◽  
Vol 18 (02) ◽  
pp. 345-354 ◽  
Author(s):  
Lorraine E. Sobers ◽  
Martin J. Blunt ◽  
Tara C. LaForce
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Rate ◽  
Gas Composition ◽  
Reservoir Properties ◽  
Injection Strategy ◽  
Oil Density ◽  
Carbon Dioxide Co2

Summary We developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are founded on pressure/volume/temperature- (PVT-) matched properties of oil found in an unconsolidated deltaic sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region, oil density ranges between 940 and 1010 kg/m3 (9 to 18°API). We use countercurrent injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir, and gas is injected in the lower portion. The two water-injection rates investigated, 100 and 200 m3/d, correspond to the water-gravity numbers 6.3 to 3.1 for our reservoir properties. We applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals in a simplified representation of the unconsolidated Forest sand found offshore Trinidad. Twelve simulation runs were conducted, varying injection-gas composition for miscible- and immiscible-gas drives, water-injection rate, and injection-well orientation. Our results show that water-over-gas injection can realize oil recoveries ranging from 17 to 30%. In each instance, more than 50% of injected CO2 remained in the reservoir, with less than 15% of the retained CO2 in the mobile phase.

Ingenious Method for Water Injection Optimization on Mature Carbonate Reservoir with Rapid Pressure Decline Problem, Case Study: XJN Field - South Sumatra, Indonesia

2021 ◽  
Author(s):  
M. Arief Salman Alfarizi ◽  
Marja Dinata ◽  
Rizki Ananda Parulian ◽  
Kamal Hamzah ◽  
Tejo Sukotrihadiyono ◽  
...  
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Material Balance ◽  
Injection Rate ◽  
Carbonate Reservoir ◽  
Integrated Analysis ◽  
Close Monitoring ◽  
Reservoir Pressure ◽  
Production Loss ◽  
Rapid Pressure

Abstract XJN field has implemented water injection as pressure maintenance since 1987, only one year after initial production. XJN is carbonate reservoir with weak aquifer underlying the oil zone. Initial reservoir pressure was 2,700 psi and peak production was 27,000 BOPD. Reservoir pressure was drop to 1,800 psi within 5 years of production. During 1991-2007, better injection management was performed to provide negative voidage. This action has managed to bring reservoir pressure back to its initial pressure, eventually enabling all wells to be converted from gaslift to naturalflow. In 2013, watercut has increased to 97% and several naturally flowing wells began to ceased-to-flow, then production mode was changed gradually from naturalflow to artificial lift using Electric Submersible Pump (ESP). In 2017-2020, there was rapid reservoir pressure decline around 300 psi/year while XJN water injection performance considered flawless. Voidage Replacement Ratio (VRR) was 1.3, but reservoir pressure was kept declining. This situation will cause ESP pump off on producer wells which in turn means big production loss. This paper will elaborate about the simple-uncommon-yet effective methods for problem detection and its solution to revive pressure and production. Analysis was began with observing the deviation of VRR and reservoir pressure, this was to estimate "leak" time of water injection. Next analysis was evaluation of injection rate leak off using material balance with reverse history matching. Reverse here means making reservoir pressure as main constraint rather than history matching goal. After that, it was continued with water injection flow path analysis. This was done by plotting production-injection-pressure data then make several small groups of injector-producer based on visible relationships. The purposes were to find key injector wells and to shut-in all inefficient ones. Furthermore, injection re-distribution was also performed based on VRR calculation on groups from previous step, water distribution priority was focused on key injector wells. These analysis have also paved the way for searching channeling possibility on injector wells. The results, XJN reservoir pressure showed an increasing trend of 100 psi/year after optimization was performed, with current pressure around 2000 psi. The increase in reservoir pressure has also made it possible to optimize ESP, field lifting has increased for 5000 BLPD. This project has also successfully secured XJN remaining oil. This project was racing with rapid pressure decline that will lead to early ESP pump off and production loss. The integrated subsurface analytical methods and actions being taken were simple but effective. Close monitoring on reservoir pressure, water injection and ESP parameters will be needed as field surveillance. Integrated analysis with surface facility engineering should also be carried out in the future in regards to surface network, injection rate and reservoir pressure.

Achieving Injectivity Optimization and Zonal Rates Allocation through Multi-Zone Intelligent Completion Technology – A Field B Case Study from Offshore Malaysia

2021 ◽  
Author(s):  
Fuziana Tusimin ◽  
Latief Riyanto ◽  
Nurul Aula A'akif Fadzil ◽  
Nur Syazana Sadan ◽  
Asba Mazidah Abu Bakar ◽  
...  
Keyword(s):  
Real Time ◽  
Pressure Support ◽  
Water Injection ◽  
Injection Rate ◽  
Fluid Distribution ◽  
Successful Implementation ◽  
Reservoir Pressure ◽  
Well Completion ◽  
Ic Technology

Abstract Properly distributing injected fluid to provide injection conformance and reservoir pressure support into the respective zones of interest in mature fields can be challenging. This challenge, with injection fluid distribution, is typically encountered in fields with high contrast in permeability, reservoir pressure, and injectivity indexes among individual zones. Deployment of intelligent completion (IC) technology to address this challenge has rapidly increased, especially in multi-zone water injector wells, due to its capabilities for real-time reservoir monitoring and control of the fluid injected into multiple zones without requiring well interventions. This paper presents a case study of successful installation of IC technology in two water injector wells in Field B offshore Sarawak. The main objective of the IC implementation is to provide an efficient water-injection method for pressure support to the nearby oil producers and counteract the gas expansion through water injection at the flank area. Water injection implementation using the IC approach can further develop the oil rims and improve oil recovery in the particular reservoir to extend the field's production life. The custom tailored inflow control valve (ICV) design is robust enough to provide control of desired zonal injection rates. Each well was installed with two sets of ICVs to control the injection rate for each dedicated zone as well as a real-time permanent downhole gauge (PDG) to monitor the pressure drop across the ICV for zonal rates allocation / analysis. Apart from conceptual and detailed engineering study of the applied IC technology, proper downhole equipment selection and integration with surface facilities are also crucial to ensure successful implementation of the IC system as a holistic solution to achieve the injection objective. Post well completion installation, a water injectivity test was performed in both the selective and commingle injection modes. During selective injection testing, different positions of the ICV were manipulated and the water injection rate was monitored. This testing approach was performed for each ICV in the well. Post selective injection testing, commingle testing was conducted at the base 9,000 bwpd and maximum injection target of 18,000 bwpd, in which the testing was successfully executed to achieve the maximum well target injection rate. This paper shall discuss the reservoir management strategy through deployment of the water injectors, conceptual well completion design, and multi-zone injectivity requirements. Details such as ICV design using pre-drill and post-drill information, final well completion strategy, pre-installation preparation, installation optimization, execution of the IC deployment, injectivity test procedure, and results are discussed as well.

Water-Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological, Seismic, and Production Data

2009 ◽  
Vol 12 (06) ◽  
pp. 865-878 ◽  
Author(s):  
Xin Feng ◽  
Xian-Huan Wen ◽  
Bo Li ◽  
Ming Liu ◽  
Dengen Zhou ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Production Data ◽  
Oil Reservoir ◽  
Reservoir Pressure ◽  
Channel Geometry ◽  
Heavy Oil Reservoir ◽  
Complex Channel

Summary BZ25-1s field in Bohai Bay, China, is characterized as a complex channelized fluvial reservoir in which small meandering channels were deposited at different geological times stacking and cross cutting each other. There are many isolated small reservoir systems following channel distributions. Early production showed steep pressure and production decline. Quick implementation of water injection was needed to arrest the fast production decline and to stabilize reservoir pressure. While designing the water-injection plan, we faced a number of challenges, such as high oil viscosity (˜200 cp), strong heterogeneity, poor reservoir connectivity, complex channel geometry, and irregular well patterns. A workflow integrating geological, well-log, seismic, and dynamic production data was developed to optimize a water injection plan for this field after a short production history. Focuses of this workflow are the selection of injection wells (converted from existing producers), timing of water injection, and the optimization of injection rates. Following the workflow, the optimal water-injection design for the areas around Platforms D and E was developed and quickly implemented within the first year of production. We started with a relatively small water-injection rate and gradually increased the injection rate to avoid the fast water breakthrough and yet to limit the pressure-decline rate. The responses from the water injection were very positive and resulted in stable reservoir pressure and increase of oil production. Before water injection, the production-decline rates were 26 and 47% in Platforms D and E, respectively. After 1 year of water injection, oil-production-decline rates in these two platforms were reduced to 19 and 14%, respectively. The responses of water injection for different well groups were analyzed in a timely fashion and adjustments to injection/production strategies were implemented accordingly. New information revealed from the water-injection response analysis was used to update the geological model to reduce the model uncertainty, as well as to adjust the water-injection strategies for better sweep efficiency. Our experiences showed that such dynamic adjustment of injection and production schedule is very important to achieve better water-injection efficiency for this heavy-oil reservoir with complex channel geometry.

Short-Term and Long-Term Aspects of Water Injection Strategy

2008 ◽  
Author(s):  
Bruno Alain Stenger ◽  
Abdulla Bakheet Al Katheeri ◽  
Hafez H. Hafez ◽  
Salem H. Al Kendi
Keyword(s):  
Water Injection ◽  
Short Term ◽  
Injection Strategy

scholarly journals Experimental investigation on water-injected twin-screw compressor for fuel cell humidification

2012 ◽  
Vol 226 (12) ◽  
pp. 2925-2932 ◽  
Author(s):  
Talal Ous ◽  
Elvedin Mujic ◽  
Nikola Stosic
Keyword(s):  
Fuel Cell ◽  
Relative Humidity ◽  
Constant Pressure ◽  
Water Injection ◽  
Injection Rate ◽  
Fuel Cell Stack ◽  
Balance Of Plant ◽  
Air Supply ◽  
Twin Screw ◽  
Mass Flow Rates

Water injection in twin-screw compressors was examined in order to develop effective humidification and cooling schemes for fuel cell stacks as well as cooling for compressors. The temperature and the relative humidity of the air at suction and exhaust of the compressor were monitored under constant pressure and water injection rate and at variable compressor operating speeds. The experimental results showed that the relative humidity of the outlet air was increased by the water injection. The injection tends to have more effect on humidity at low operating speeds/mass flow rates. Further humidification can be achieved at higher speeds as a higher evaporation rate becomes available. It was also found that the rate of power produced by the fuel cell stack was higher than the rate used to run the compressor for the same amount of air supplied. The efficiency of the balance of plant was, therefore, higher when more air is delivered to the stack. However, this increase in the air supply needs additional subsystems for further humidification/cooling of the balance-of-plant system.

scholarly journals A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System

1965 ◽  
Vol 5 (02) ◽  
pp. 131-140 ◽  
Author(s):  
K.P. Fournier
Keyword(s):  
Thermal Expansion ◽  
Oil Recovery ◽  
Viscosity Ratio ◽  
Water Injection ◽  
Injection Rate ◽  
Heat Losses ◽  
Hot Water ◽  
Radial System ◽  
System Equation ◽  
Finite Difference Equations

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

Comparison of Water Thickness Profiles of Compressed PEMFC GDLs

2011 ◽  
Author(s):  
Pradyumna Challa ◽  
James Hinebaugh ◽  
A. Bazylak
Keyword(s):  
Water Content ◽  
Liquid Water ◽  
Water Distribution ◽  
Polymer Electrolyte Membrane ◽  
Water Injection ◽  
Liquid Water Content ◽  
Gas Diffusion ◽  
Injection Rate ◽  
Water Levels ◽  
Ex Situ

In this paper, through-plane liquid water distribution is analyzed for two polymer electrolyte membrane fuel cell (PEMFC) gas diffusion layers (GDLs). The experiments were conducted in an ex situ flow field apparatus with 1 mm square channels at two distinct flow rates to mimic water production rates of 0.2 and 1.5 A/cm2 in a PEMFC. Synchrotron radiography, which involves high intensity monochromatic X-ray beams, was used to obtain images with a spatial and temporal resolution of 20–25 μm and 0.9 s, respectively. Freudenberg H2315 I6 exhibited significantly higher amounts of water than Toray TGP-H-090 at the instance of breakthrough, where breakthrough describes the event in which liquid water reaches the flow fields. While Freudenberg H2315 I6 exhibited a significant overall decrease in liquid water content throughout the GDL shortly after breakthrough, Toray TGP-H-090 appeared to retain breakthrough water-levels post-breakthrough. It was also observed that the amount of liquid water content in Toray TGP-H-090 (10%.wt PTFE) decreased significantly when the liquid water injection rate increased from 1 μL/min to 8 μL/min.

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.

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