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

2019 ◽  
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 forecasted by the industry 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 (EUR) 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 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 4,845 wells is still growing linearly with the square root of time; and (2) 6,401 wells are already in exponential decline after approximately seven years on production. In addition, 2,363 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 1,279 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 policy-makers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, 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.

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.

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.

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

2020 ◽  
Vol 142 (5) ◽  
Author(s):  
Youwei He ◽  
Shiqing Cheng ◽  
Zhe Sun ◽  
Zhi Chai ◽  
Zhenhua Rui
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Co2 Injection ◽  
Production Rates ◽  
Well Production ◽  
Well Completion ◽  
Tight Formations ◽  
Fractured Horizontal Wells ◽  
The Impact

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

The Effect of Irradiation on Immiscible Fluids for Increased Oil Production With Horizontal Wells

2005 ◽  
Author(s):  
Nancy Bjorndalen ◽  
Shabbir Mustafiz ◽  
M. R. Islam
Keyword(s):  
Numerical Model ◽  
Crude Oil ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Oil Production ◽  
Horizontal Wells ◽  
Immiscible Fluids ◽  
Paraffin Wax ◽  
Horizontal Section ◽  
Temperature Changes

Oil recovery using horizontal wells gives an undeniable benefit to the petroleum industry. One of the problems of using this method is that the wells can plug due to pressure and temperature changes. The components of crude oil such as asphaltene and paraffin wax can precipitate in the horizontal section of the well causing a loss of productivity and profit. Microwave or irradiation has been proposed to remove these precipitates remotely. The effect of microwaves on crude oil properties has been studied and a numerical model is presented to gain an understanding of the effect of the rise in temperature. These results include temperature increases for various concentrations of crude oil, and paraffin wax under different exposure times. The effect that different media (bentonite and gypsum) has on the temperature of these components has also been studied. By understanding the temperature rise, one can determine the effect that irradiation will have on oil production. Overall, the agreement between experimental and numerical results was acceptable.

Designing the Thermal Enhanced Oil Recovery as a Key Technology of High Viscosity Oil Production

2021 ◽  
Author(s):  
Mukhtar Shakenuly Shaken ◽  
Baurzhan Yerikovich Zhiyengaliyev ◽  
Altynbek Suleymenuly Mardanov ◽  
Adil Sultangaliyevich Dauletov
Keyword(s):  
Oil Recovery ◽  
Hydrodynamic Model ◽  
Oil Production ◽  
Horizontal Wells ◽  
High Viscosity ◽  
Oil Reservoirs ◽  
Production Rates ◽  
Cyclic Steam Stimulation ◽  
High Viscosity Oil ◽  
Steam Stimulation

Abstract Due to the decrease in "easy" oil reserves, oil companies are focusing on "hard-to-recover" reserves, in particular, high-viscosity oil reservoirs. Shallow oil reservoirs are mainly concentrated in the Cretaceous horizons, in the western region of the country, along the Caspian coast. One of them is a high-viscosity oil reservoir, consisting of three Cretaceous horizons. The average viscosity of oil in reservoir conditions is around 746.7 cP. The current achieved oil production is only 5% of the initial recoverable reserves, and designed oil recovery factor is 38% and implies the full-scale application of thermal methods of EOR. The objective of this work was to choose the most suitable thermal method of EOR and to assess the prospects of applicability with the calculation of economic feasibility. Considering the geological features of the reservoir, the cyclic steam stimulation was chosen as the optimal method to increase oil recovery. In order to assess the expediency of this technology, was initiated project on thermal modeling the technology based on the current geological and hydrodynamic model of the field, using the results of laboratory studies, calculations were performed on imagined horizontal wells, and carried out the analysis of technical and economic efficiency. According to the results of calculations on the hydrodynamic model, the production rates using the technology of cyclic steam stimulation in horizontal wells are 30% higher than the production rates of "cold production", and the difference in accumulated oil production over 5 years will be 20–30%.

Sand on Demand: A Laboratory Investigation on Improving Productivity in Horizontal Wells Under Heavy-Oil Primary Production—Part II

SPE Journal ◽  
2012 ◽  
Vol 17 (04) ◽  
pp. 1012-1028 ◽  
Author(s):  
Brigida Meza-Díaz ◽  
Ron Sawatzky ◽  
Ergun Kuru
Keyword(s):  
Heavy Oil ◽  
Fluid Velocity ◽  
Oil Production ◽  
Horizontal Wells ◽  
Recovery Process ◽  
Sand Production ◽  
Production Rates ◽  
Confining Stress ◽  
On Demand ◽  
Slot Size

Summary The cold-production-recovery process, also known as cold heavy-oil production with sand (CHOPS), is a method for enhancing primary heavy-oil production by aggressively producing sand. It is successful in vertical (or slanted or deviated) wells in western Canada. In this process, large amounts of sand are produced on a continuing basis along with heavy oil. Attempts at cold production in horizontal wells have not been particularly successful. When sand production has been generated in horizontal wells, these wells have tended to become plugged with sand. This paper presents the results of experiments performed to assess the feasibility of applying cold heavy-oil production in horizontal wells that have been completed with slotted liners using less-aggressive (i.e., managed) sand-production strategies. Specifically, the effects of slot size, confining stress, fluid velocity, and sand-grain sorting on sand production were investigated. The results indicate that slot-size selection is critical for establishing "sand on demand." From the experiments, a correlation between slot size and controlled sand production was found for well-sorted sands. This correlation should allow for the specification of appropriate slot sizes for target reservoirs containing well-sorted sands. In the experiments, when flow rates resulted in low but persistent sand production, channels and/or elliptical dilated zones were created that greatly enhanced the effective permeability near the slot. This observation suggests that producing at low and steady sand cuts for a long period of time might bring two benefits: a way to transport the sand out of the well without causing plugging and the creation of high-permeability channels or zones that can improve production from the reservoir. To summarize, if the appropriate slot size were combined with the right drawdown rates, controlled sand production could be achieved, with attendant significant increases in permeability. This suggests that substantially increased oil-production rates could be achieved from horizontal wells if sand-production rates could be maintained at low but persistent levels.

Geochemistry and age of groundwater in the Williston Basin, USA: Assessing potential effects of shale-oil production on groundwater quality

2020 ◽  
pp. 104833
Author(s):  
Peter B. McMahon ◽  
Joel M. Galloway ◽  
Andrew G. Hunt ◽  
Kenneth Belitz ◽  
Bryant C. Jurgens ◽  
...  
Keyword(s):  
Groundwater Quality ◽  
Oil Production ◽  
Williston Basin ◽  
Shale Oil

Study and Comparison of Vibration-Based Intrusive and Non-Intrusive Sand Monitoring System

2013 ◽  
Vol 701 ◽  
pp. 440-444
Author(s):  
Gang Liu ◽  
Peng Tao Liu ◽  
Bao Sheng He
Keyword(s):  
Real Time ◽  
Monitoring System ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Field ◽  
Sand Production ◽  
The Status

Sand production is a serious problem during the exploitation of oil wells, and people put forward the concept of limited sand to alleviate this problem. Oil production with limited sanding is an efficient mod of production. In order to complete limited sand exploitation, improve the productivity of oil wells, a real-time sand monitoring system is needed to monitor the status of wells production. Besides acoustic sand monitoring and erosion-based sand monitoring, a vibration-based sand monitoring system with two installing styles is proposed recently. The paper points out the relationships between sand monitoring signals collected under intrusive and non-intrusive installing styles and sanding parameters, which lays a good foundation for further study and actual sand monitoring in oil field.

Increasing the Productivity of Horizontal Wells Through Multistage Hydraulic Fracturing Using a Working Fluid Based on a New Biopolymer System

2021 ◽  
Author(s):  
Nikolay Mikhaylovich Migunov ◽  
Aleksey Dmitrievich Alekseev ◽  
Dinar Farvarovich Bukharov ◽  
Vadim Alexeevich Kuznetsov ◽  
Aleksandr Yuryevich Milkov ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Russian Federation ◽  
Oil Production ◽  
Horizontal Wells ◽  
Working Fluid ◽  
High Tech ◽  
Executive Order ◽  
Bazhenov Formation ◽  
Multistage Hydraulic Fracturing ◽  
The Russian Federation

Abstract According to the US Energy Agency (EIA), Russia is the world leader in terms of the volume of technically recoverable "tight oil" resources (U.S. Department of Energy, 2013). To convert them into commercial production, it is necessary to create cost-effective development technologies. For this purpose, a strategy has been adopted, which is implemented at the state level and one of the key elements of which is the development of the high-tech service market. In 2017, the Minister of Energy of the Russian Federation, in accordance with a government executive order (Government Executive Order of the Russian Federation, 2014), awarded the Gazprom Neft project on the creation of a complex of domestic technologies and high-tech equipment for developing the Bazhenov formation with the national status. It is implemented in several directions and covers a wide range of technologies required for the horizontal wells drilling and stimulating flows from them using multi-stage hydraulic fracturing (MS HF) methods. Within the framework of the technological experiment implemented at the Palyanovskaya area at the Krasnoleninskoye field by the Industrial Integration Center "Gazpromneft - Technological Partnerships" (a subsidiary of Gazprom Neft), from 2015 to 2020, 29 high-tech wells with different lengths of horizontal wellbore were constructed, and multistage hydraulic fracturing operations were performed with various designs. Upon results of 2020, it became possible to increase annual oil production from the Bazhenov formation by 78 % in comparison with up to 100,000 tons in 2019. The advancing of development technologies allowed the enterprise to decrease for more than twice the cost of the Bazhenov oil production from 30 thousand rubles per ton (69$/bbl) at the start of the project in 2015 to 13 thousand rubles (24$/bbl) in 2020. A significant contribution to the increase in production in 2020 was made by horizontal wells, where MS HF operations were carried out using an experimental process fluid, which is based on the modified Si Bioxan biopolymer. This article is devoted to the background of this experiment and the analysis of its results.

Sign in / Sign up

Export Citation Format

Share Document