Development of World-Class Oil Production and Water Injection Rate and High Ultimate-Recovery Wells in Deepwater Turbidites--Bonga Example

2009 ◽  
Vol 24 (02) ◽  
pp. 293-302
Author(s):  
Solomon O. Inikori ◽  
Bert Coxe ◽  
Ebenezer Ageh ◽  
Jaap W. Van der Bok
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
World Class

scholarly journals Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

An Efficient Workflow for Production Allocation During Water Flooding

2016 ◽  
Vol 139 (3) ◽  
Author(s):  
Vahid Azamipour ◽  
Mehdi Assareh ◽  
Mohammad Reza Dehghani ◽  
Georg M. Mittermeir
Keyword(s):  
Objective Function ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Coarse Grid ◽  
Recovery Factor ◽  
Total Water ◽  
Production Schedule ◽  
Production Rates ◽  
Total Oil

This paper presents an efficient production optimization scheme for an oil reservoir undergoing water injection by optimizing the production rate for each well. In this approach, an adaptive version of simulated annealing (ASA) is used in two steps. The optimization variables updating in the first stage is associated with a coarse grid model. In the second step, the fine grid model is used to provide more details in final solution search. The proposed method is formulated as a constrained optimization problem defining a desired objective function and a set of existing field/facility constraints. The use of polytope in the ASA ensures the best solution in each iteration. The objective function is based on net present value (NPV). The initial oil production rates for each well come from capacity and property of each well. The coarse grid block model is generated based on average horizon permeability. The proposed optimization workflow was implemented for a field sector model. The results showed that the improved rates optimize the total oil production. The optimization of oil production rates and total water injection rate leads to increase in the total oil production from 315.616 MSm3 (our initial guess) to 440.184 MSm3, and the recovery factor is increased to 26.37%; however, the initial rates are much higher than the optimized rates. Beside this, the recovery factor of optimized production schedule with optimized total injection rate is 3.26% larger than the initial production schedule with optimized total water injection rate.

scholarly journals Developing a new technique for the simultaneous optimization of both segmented time and injection rate for water flooding reservoirs: An analysis of Shengli Oilfield XIN-42 reservoir block

2020 ◽  
Vol 38 (6) ◽  
pp. 2356-2369
Author(s):  
Yinfei Ma ◽  
Anfeng Shi ◽  
Xiaohong Wang ◽  
Baoguo Tan ◽  
Hongxia Sun
Keyword(s):  
Net Present Value ◽  
Water Injection ◽  
Oil Production ◽  
Adjustment Costs ◽  
Injection Rate ◽  
Production Optimization ◽  
Simultaneous Optimization ◽  
Water Flooding ◽  
Present Value ◽  
Oil Production Optimization

The adjustment and control of the water injection rate is a commonly used method for increasing the cumulative oil production of waterflooded reservoirs. This article studies the production optimization problem under the condition of a fixed total water injection rate. The production process is divided into several segments. Considering the correlation between the segment’s time intervals and the well’s injection rate distribution, a simultaneous optimization of both segmented time and injection rate is proposed for enhancing net present value. Both empirical simulations and field application demonstrate that the suggested methods produce the highest increase in net present value – of approximately 13% and 10%, respectively – and significantly improve water flooding efficiency compared to other conventional schemes, such as segmented oil production optimization, cumulative oil production optimization and Bang-Bang control. The proposed methods under a 2-segment division increase oil production efficiency and greatly reduce adjustment costs.

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.

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.

Swing Operation Envelope of River-Sourced Water Treatment Facility for Water Injection Purpose in Banyu Urip Field

2021 ◽  
Author(s):  
Muhammad Amin Rois ◽  
Willy Dharmawan
Keyword(s):  
Water Treatment ◽  
River Water ◽  
Rainy Season ◽  
Treatment Cost ◽  
Water Injection ◽  
Injection Rate ◽  
Raw Water ◽  
Treatment Facility ◽  
Water Parameters ◽  
Water Basin

Abstract Banyu Urip reservoir management heavily rely on river-sourced water as water injection to meet Voidage Replacement Ratio target of 1. The treatment facility which consist of Raw Water Basin, Clarifiers, Multi Media Fine (MMF) Filters and Cartridge Filters, is sensitive to seasonal transition and river condition. This paper shares lesson learnt in operating such facility and troubleshooting guidance to overcome challenges of high turbidity during rainy season and lack of river water volume during drought season. To maintain the design intent of Banyu Urip (BU) water treatment facility in achieving water injection quality and quantity at reasonable cost, following activities were undertaken: [1] Critical water parameters data gathering & analysis across each unit; [2] Clarifier Chemical injection dosage verification based on laboratory test; [3] MMF Media coring inspection to assess the filtering media condition; [4] MMF Filters backwash parameters optimization; [5] MMF Filter on-off valve sequencing optimization to address water hammering issue; [6] Water injection rate management to deal with river water source availability along the year. Critical water parameters analysis revealed that chemical dosages were in-adequate to treat the five times higher turbidity coming into Clarifiers during early rain 2019. On top of this, low Raw Water Basin level at the end of long drought further contributed to jeopardize Clarifier's operation. Although in-adequate chemicals injection was resolved at early 2020, the treatment cost remained high, especially on filtration section. Media coring result on MMF Filters confirmed that the filtering media have been poisoned by carried-over mud from Clarifiers during upset. The operation of MMF Filters required extensive optimization on backwash parameters to successfully recover the MMF Filters performance without media replacement. Latest media coring on the worst MMF Filter showed that there was no more top mud layer and the amount of trapped mud had been decreased significantly. Cartridge Filter replacement interval was improved from 38 hours to 186 hours, therefore water treatment cost dropped with quite significant margin. Additionally, the availability of each MMF Filters was also improved. At the same time, the high water injection rate during 2020 rainy season, had successfully increased reservoir pressure buffer up to its maximum point as the anticipation of prolonged drought season. This paper provides the troubleshooting guidance for MMF Filter application in season-prone water treatment facility including insights on interpretation of media coring result and linking it back to optimization strategy on the MMF Filters drain down time for effective backwash process without having excessive media loss.

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