A Superior Shale Oil EOR Method for the Permian Basin

2021 ◽  
Author(s):  
Robert Downey ◽  
Kiran Venepalli ◽  
Jim Erdle ◽  
Morgan Whitelock
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Lower Cost ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Artificial Lift

Abstract The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil. A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.

Evaluation of Artificial Lift Methods to Increase Oil Production from Depleting Oil Wells in Gulf of Mexico

2020 ◽  
Vol 10 (5) ◽  
pp. 137-141
Author(s):  
Saurabh Goswami ◽  
Dr. T. S. Chouhan
Keyword(s):  
Gulf Of Mexico ◽  
Oil Recovery ◽  
Energy Demand ◽  
Research Work ◽  
Oil Production ◽  
Oil Wells ◽  
Artificial Lift ◽  
Big Picture ◽  
Production Form ◽  
Global Energy Supply

This paper summarizes the research work with reference to artificial lift methods to increase oil production form mature oil wells in Gulf of Mexico.  Increase oil production or oil recovery from oil reservoirs is very important. If the average worldwide recovery factor from hydrocarbon reservoirs can be increased beyond current limits, it will alleviate a number of issues related to global energy supply. Currently the daily oil production comes from mature or maturing oil fields and reserves replacement is not keeping pace with the growing energy demand.   This paper presents big picture overview of artificial lift methods for mature oil wells in Gulf of Mexico.

scholarly journals Shale oil production and groundwater: What can we learn from produced water data?

PLoS ONE ◽  
2021 ◽  
Vol 16 (4) ◽  
pp. e0250791
Author(s):  
Haoying Wang
Keyword(s):  
Produced Water ◽  
Groundwater Resources ◽  
Oil Production ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Deep Basin ◽  
Freshwater Aquifers ◽  
The Impact ◽  
The Relationship

As oil production in the Permian Basin surges, the impact of shale production on groundwater resources has become a growing concern. Most existing studies focus on the impact of shale production on shallow freshwater aquifers. There is little understanding of the shale development’s impact on other groundwater resources (e.g., deep carbonate aquifers and deep basin meteoric aquifers). The possible natural hydraulic connections between shallow aquifers and formation water suggest such an impact can be consequential. This study explores the relationship between shale production and groundwater using produced water (PW) samples from active unconventional oil wells. Focusing on the most productive portion of the Permian Basin—the four-county region in Southeast New Mexico between 2007 and 2016, a large produced water dataset allows us to analyze the conditional correlations between shale oil production and PW constituents. The results suggest that (1) expanding from primarily conventional wells to unconventional wells during the recent shale boom has led to dramatic increases of the TDS, chloride, sodium, and calcium levels in groundwater (i.e., producing formation). (2) Nearby oil well density positively correlates with the TDS, chloride, and sodium levels in the PW samples.

scholarly journals Physical Scaling of Oil Production Rates and Ultimate Recovery from All Horizontal Wells in the Bakken Shale

Energies ◽  
2020 ◽  
Vol 13 (8) ◽  
pp. 2052 ◽  
Author(s):  
Wardana Saputra ◽  
Wissem Kirati ◽  
Tadeusz Patzek
Keyword(s):  
Petroleum Industry ◽  
Oil Production ◽  
Horizontal Wells ◽  
Accurate Method ◽  
Oil Wells ◽  
Shale Oil ◽  
Square Root ◽  
Production Rates ◽  
Time Flow ◽  
Bakken Shale

A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict the Estimated Ultimate Recovery (EUR), we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4845 wells is still growing linearly with the square root of time; and (2) 6401 wells are already in exponential decline after approximately seven years on production. In addition, 2363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policymakers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, the petroleum industry may adopt our physics-based method as an alternative to the overly optimistic hyperbolic DCA that yields an ‘illusory picture’ of shale oil resources.

Global Optimization of Gas Allocation to a Group of Wells in Artificial Lift Using MATLAB

2001 ◽  
Author(s):  
Gabriel A. Alarcón ◽  
Carlos F. Torres-Monzón ◽  
Nellyana Gonzalo ◽  
Luis E. Gómez
Keyword(s):  
Production Rate ◽  
Optimization Technique ◽  
Gas Injection ◽  
Nonlinear Function ◽  
Oil Production ◽  
Oil Well ◽  
Artificial Lift ◽  
Total Oil ◽  
Gas Lift ◽  
Injection Rates

Abstract Continuous flow gas lift is one of the most common artificial lift method in the oil industry and is widely used in the world. A continuous volume of gas is injected at high pressure into the bottom of the tubing, to gasify the oil column and thus facilitate the extraction. If there is no restriction in the amount of injection gas available, sufficient gas can be injected into each oil well to reach maximum production. However, the injection gas available is generally insufficient. An inefficient gas allocation in a field with limited gas supply also reduces the revenues, since excessive gas injection is expensive due to the high gas prices and compressing costs. Therefore, it is necessary to assign the injection gas into each well in optimal form to obtain the field maximum oil production rate. The gas allocation optimization can be considered as a maximization of a nonlinear function, which models the total oil production rate for a group of wells. The variables or unknowns for this function are the gas injection rates for each well, which are subject to physical restrictions. In this work a MATLAB™ nonlinear optimization technique with constraints was implemented to find the optimal gas injection rates. A new mathematical fit to the “Gas-Lift Performance Curve” is presented and the numeric results of the optimization are given and compared with results of other methods published in the specialized literature. The optimization technique proved fast convergence and broad application.

Characterizing hydraulic and natural fractures properties in shale oil well in Permian basin using assisted history matching

Fuel ◽  
2020 ◽  
Vol 275 ◽  
pp. 117950
Author(s):  
Sutthaporn Tripoppoom ◽  
Xin Wang ◽  
Zhe Liu ◽  
Wei Yu ◽  
Hongbing Xie ◽  
...  
Keyword(s):  
History Matching ◽  
Oil Well ◽  
Shale Oil ◽  
Natural Fractures ◽  
Permian Basin ◽  
Assisted History Matching

scholarly journals Electrical Submersible Pump Design in Vertical Oil Wells

2020 ◽  
Vol 4 (4) ◽  
pp. 1-7
Author(s):  
Gomaa S
Keyword(s):  
Oil Wells ◽  
Maintenance Cost ◽  
Oil Well ◽  
Submersible Pump ◽  
Reservoir Properties ◽  
Pump Design ◽  
Artificial Lift ◽  
Complete Study ◽  
Electrical Submersible Pump

Artificial Lift is a very essential tool to increase the oil production rate or lift the oil column in the wellbore up to the surface. Artificial lift is the key in case of bottom hole pressure is not sufficient to produce oil from the reservoir to the surface. So, a complete study is carried to select the suitable type of artificial lift according to the reservoir and wellbore conditions like water production, sand production, solution gas-oil ratio, and surface area available at the surface. Besides, the maintenance cost and volume of produced oil have an essential part in the selection of the type of artificial lift tool. Artificial lift tools have several types such as Sucker Rod Pump, Gas Lift, Hydraulic Pump, Progressive Cavity Pump, Jet Pump, and Electrical Submersible Pump. All these types require specific conditions for subsurface and surface parameters to apply in oil wells. This paper will study the Electrical Submersible Pump “ESP” which is considered one of the most familiar types of artificial lifts in the whole world. Electrical Submersible Pump “ESP” is the most widely used for huge oil volumes. In contrast, ESP has high maintenance and workover cost. Finally, this paper will discuss a case study for the Electrical Submersible pump “ESP” design in an oil well. This case study includes the entire well and reservoir properties involving fluid properties to be applied using Prosper software. The results of the design model will impact oil productivity and future performance of oil well.

scholarly journals OPTIMAL OPERATION OF ELECTRICAL POWER GENERATORS FOR OIL WELLS OPERATED BY ARTIFICIAL LIFTING AT RUMILA FIELD

2019 ◽  
Vol 20 (11-12) ◽  
pp. 127-132 ◽  
Author(s):  
Majid Abdulhameed Abdulhy Al-Ali ◽  
V. Yu. Kornilov ◽  
A. G. Gorodnov
Keyword(s):  
Electrical Power ◽  
Oil Production ◽  
Optimal Operation ◽  
Oil Wells ◽  
Oil Field ◽  
Parallel Operation ◽  
Economic Gain ◽  
Power Generators ◽  
Artificial Lift ◽  
Electrical Submersible Pumps

Numerous oil wells within Rumaila field contain Electrical Submersible Pumps (ESPs). ESPs are utilised to maximise the oil production from existing wells by providing artificial lift where pressure is low, which helps maintain oil production levels. The number of ESPs installed throughout the Rumaila. Field is growing consistently to sustain oil field production. Due to the remote locations for each of the ESPs the current strategy is to supply power to ESPs using individual diesel engine generators located at each remote ESP well site. This is an inefficient design, as individual diesel engines are resource intensive due to maintenance and frequent diesel filling. The generators are also a source of significant unreliability causing ESP shutdowns/trips resulting in extended downtime. Given the above a Pre-FEED has been carried out considering supplying ESPs using OHTL’s supplying electrical power from EPP to ESPs in Area C. by uses parallel operation of diesel Generators , we could to constrict 124 from 184 and use 60 only ,by this we get high economic gain and technique, in additional that environmental protection by decreasing pollution.

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.

Global Optimization of Gas Allocation to a Group of Wells in Artificial Lift Using Nonlinear Constrained Programming

2002 ◽  
Vol 124 (4) ◽  
pp. 262-268 ◽  
Author(s):  
Gabriel A. Alarco´n ◽  
Carlos F. Torres ◽  
Luis E. Go´mez
Keyword(s):  
Production Rate ◽  
Optimization Technique ◽  
Gas Injection ◽  
Nonlinear Function ◽  
Oil Production ◽  
Oil Well ◽  
Artificial Lift ◽  
Total Oil ◽  
Gas Lift ◽  
Injection Rates

Continuous flow gas lift is one of the most common artificial lift methods widely used in the oil industry. A continuous volume of high-pressure gas is injected as deep as possible into the tubing, to gasify the oil column, and thus facilitate the production. If there is no restriction in the amount of injection gas available, sufficient gas can be injected into each oil well to reach maximum production. However, the injection gas available is generally insufficient. An inefficient gas allocation in a field with limited gas supply reduces the revenues, since excessive gas injection is expensive due to the high gas prices and compressing costs. Therefore, it is necessary to assign the injection gas into each well in optimal form to obtain the field maximum oil production rate. The gas allocation optimization can be considered as a maximization of a nonlinear function, which models the total oil production rate for a group of wells. The variables or unknowns for this function are the gas injection rates for each well, which are subject to physical restrictions. In this work a nonlinear optimization technique, based on an objective function with constraints, was implemented to find the optimal gas injection rates. A new mathematical fit to the gas-lift performance curve (GLPC) is presented and the numeric results of the optimization are given and compared with those of other methods published in the specialized literature. The GLPC can be either measured in the field, or alternatively generated by computer simulations, by mean of nodal analysis. The optimization technique proved fast convergence and broad application.

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