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2022 ◽  
Vol 9 ◽  
Author(s):  
Yifan Fan ◽  
Shikuan Zhang ◽  
Yonghui Huang ◽  
Zhonghe Pang ◽  
Hongyan Li

Recoverable geothermal resources are very important for geothermal development and utilization. Generally, the recovery factor is a measure of available geothermal resources in a geothermal field. However, it has been a pre-determined ratio in practice and sustainable utilization of geothermal resources was not considered in the previous calculation of recoverable resources. In this work, we have attempted to develop a method to calculate recoverable geothermal resources based on a numerical thermo-hydraulic coupled modeling of a geothermal reservoir under exploitation, with an assumption of sustainability. Taking a geothermal reservoir as an example, we demonstrate the effectiveness of the method. The recoverable geothermal resources are 6.85 × 1018 J assuming a lifetime of 100 years in a well doublet pattern for geothermal heating. We further discuss the influence of well spacing on the recoverable resources. It is found that 600 m is the optimal well spacing with maximum extracted energy that conforms to the limit of the pressure drop and no temperature drop in the production well. Under the uniform well distribution pattern for sustainable exploitation, the recovery factor is 26.2%, which is higher than the previous value of 15% when depending only on lithology. The proposed method for calculating the recoverable geothermal resources is instructive for making decisions for sustainable exploitation.


2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.


2021 ◽  
Vol 9 ◽  
Author(s):  
Wenzhen Yuan ◽  
Dailei Zhang ◽  
Yi Zhang ◽  
Jun Gao ◽  
Tongzhe Liu ◽  
...  

The sustainable development of a shallow aquifer geothermal reservoir is strongly affected by the reinjection–production strategy. However, the reinjection–production strategy optimization of a small-scale exploitation unit with tens of meters of well spacing is site specific and has not yet been fulfilled. This study numerically investigates sustainable heat extraction based on various reinjection–production strategies which were conducted in a single-phase aquitard–aquifer geothermal system in Huailai County, Hebei Province, China. The response of the water level and production temperature is mainly discussed. The numerical results show that production without reinjection induces the highest production temperature and also the water level drawdown. Although reinjection in a single doublet well system is conducive to the control of water level drawdown, the introduction of the thermal breakthrough problem causes a decrease in the production temperature. The thermal breakthrough and sustainability of geothermal reservoirs highly depend on the well spacing between the production and reinjection wells, especially for the small-scale field. Therefore, a large well spacing is suggested. A multi-well system facilitates the control of water level drawdown while bringing intensive well interference and thermal breakthrough. Large spacing between the production and reinjection wells is also the basic principle for the design of the multi-well system. A decrease in openhole length leads to an increase in the production temperature and output thermal power. An increase in the production rate affects the thermal breakthrough highly and shortens the lifetime of the geothermal system. Furthermore, the extracted thermal energy is highly affected by the reduction in the reinjection temperature. The results in this study can provide references to achieve sustainable geothermal exploitation in small-scale geothermal reservoirs.


Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 5) ◽  
Author(s):  
Jian Shen ◽  
Mingtao Chen ◽  
Shengtao Li ◽  
Zhenpeng Cui ◽  
Yilong Yuan ◽  
...  

Abstract The development of sandstone-type geothermal energy is an important part of the development of geothermal resources and has great significance in promoting environmental protection and energy structural transformation. In sandstone geothermal energy development, recharging is the main method to ensure bottom hole pressure. However, the pressure and temperature changes of sandstone reservoirs under recharge conditions have not been extensively studied. It is easy to ignore the hydraulic relationship between the production and the injection wells, which leads to an increased risk of thermal breakthrough. Therefore, a three-dimensional hydrothermal coupling model is established, and simulation studies of different flow rates, well lengths, and well spacings are completed in this paper. Here, we show the numerical simulation results. The low temperature expansion zone and hydrostatic pressure near the injection well increase with increasing flow rate, and the maximum expansion of the low temperature zone is about 350 m. The low temperature expansion area near the injection well has a small relationship with the well spacing, and the increase in hydrostatic pressure is proportional to the well spacing. As the length of the well increases, the increase in hydrostatic pressure near the injection well decreases, indicating that the injected water under the long well section easily enters the reservoir. When no thermal breakthrough occurs and the hydrostatic pressure drops significantly near the production well, it is recommended that the flow rate be controlled at approximately 20–25 L/s, the well spacing should be 600–800 m, and the well length should be greater than 100 m.


2021 ◽  
Author(s):  
Fayang Jin ◽  
Qihang Li ◽  
Yong Liu ◽  
Wanfen Pu ◽  
Chengdong Yuan ◽  
...  

Abstract The HD Oilfield, operated by PetroChina, is located in Tarim Basin. It is characterized by high temperature (112 ℃) and high salinity (291000 mg/L), and developed by wide spacing of wells (average 700 m). High vertical and areal heterogeneity lead to early water breakthrough and a poor water sweep efficiency. Effective conformance control is urgently needed, but harsh reservoir conditions, wide well spacing, and discontinuous interlayers pose great challenges for conformance treatments in this field. Because of wide well spacing and discontinuous interlayers, water channeling and crossflow in in-depth part of reservoir could still occur after conformance treatment. To prevent this, in-depth conformance improvement treatments with injecting large volumes of low-cost profile control agents were proposed. To achieve this goal, we designed delayed water-swelling, flexible gel particles that have high deformability and elasticity. Simultaneously, to meet the harsh reservoir conditions, gel particles were designed to have long-term tolerance to high temperature and high salinity. The first treatment was implemented in May 2016, and the total incremental oil by June 2019 was 17347 tons. The treatment validity is more than 36 months, and it keeps being effective. Until now, 9 treatments have been finished. The total incremental oil is 102100 tons until May 2020, and the increment is still going on. The input-output ratio for these 9 treatments is about 8.45, which indicates the treatments were an economic and technical success. In this paper, first we describe the design of gel particles and their properties evaluation by extensive experiments, including water-swelling ability, long-term tolerance to high temperature and high salinity, elasticity, tenacity, injectivity, selectivity, plugging ability, and scouring resistance, etc. Then, we present operation design and control in the field, which is especially important for the success of these treatments. Furthermore, according to production performance as well as the wellhead pressure drop curve, pressure curve of water injection, and water injectivity in injection well, treatment results are discussed in detail to evaluate if the treatment is successful or not. Finally, several important experiences with respect to how to do operation design and field control are summarized. This paper documents a successful case history of in-depth waterflood conformance improvement in wide spacing of wells. These successful field cases together with summarized experience will provide a detailed guide and an updated framework for conformance improvement treatment for operators. In addition, this paper presents an alternative agent, i.e., delayed water-swelling, flexible gel particles, for in-depth waterflood conformance improvement in high temperature and high salinity reservoirs.


2021 ◽  
Author(s):  
Amal Al-Sane ◽  
Mohammad A. Al-Bahar ◽  
Anup Bora ◽  
Prashant S. Dhote ◽  
Gopi Nalla ◽  
...  

Abstract During the progressive development of mature fields, it is imperative to drill many infill wells to accelerate production and access bypassed oil. Optimizing the infill well spacing is always the concern to reduce interference with existing wells and improve recovery. In the present study, using intelligent data mining techniques, a new analysis and visualization tool has been developed and implemented to estimate and map drainage radius by well to assess the efficiency of the current development pattern and properly plan future wells. The tool deployed several performance-based techniques to estimate the contacted stock-tank oil initially in place (STOIIP) by each existing well, and outcomes can be compared between techniques for validation. The contacted STOIIP is then converted into an effective drainage radius by well using reservoir properties from the geo-cellular model. The evaluated reservoir is subdivided vertically into pay zones drained by the wells based on geological barriers/baffles to flow and connectivity across the zones. The tool estimates drainage radii of the wells produced from the reservoir using five different methods. The resultant Proved Developed Producing (PDP) reserves polygon maps are generated for the connected zones. The drainage radii of wells with behind-casing opportunities are estimated based on correlation and adjacent wells methods, and Proved Developed Non-Producing (PDNP) reserves polygon maps were generated. Well interference density is estimated based on overlapping drainage radii polygons with adjacent well locations, which has then been validated with production and pressure data from the wells. This paper describes the methodology by which the well drainage radii and well interference density can be estimated and implemented on a selected reservoir. This workflow can be successfully used to identify drained and undrained areas around the wellbore and opportunities for additional infill wells in the various pay zones of the reservoir. This exercise observed consistency in the drainage radii cumulative distribution from decline curve analysis methods and the No-Further-Activities (NFA) simulation case.


2021 ◽  
Author(s):  
Ahmad Khanifar ◽  
Benayad Nourreddine ◽  
Mohd Razib Bin Abd Raub ◽  
Raj Deo Tewari ◽  
Mohd Faizal Bin Sedaralit

Abstract A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in the final steering committee. Subsequently, due to the eventual plunging global crude oil price, the project was then reprioritized and adjourned correspondingly within Petronas’ upstream portfolio management. Further phased development including a producing pilot has been debated with the main objective to address key technical and business uncertainties and risks associated with applying CEOR process.


2021 ◽  
Vol 11 (23) ◽  
pp. 11408
Author(s):  
Ja-Young Goo ◽  
Jae-Hyun Kim ◽  
Young Jae Lee ◽  
Soonjae Lee

A non-pumping reactive well (NPRW) is a subsurface structure that prevents contaminant spread using many non-pumping wells containing reactive media. For the construction of an effective NPRW, a sufficiently small spacing between wells is an important design factor to prevent contaminant leakage. However, close well construction is not recommended because of concerns about the decreased stability of adjacent wells under field conditions. In this research, we proposed a sawtooth array of NPRW as a practical configuration to minimize well spacing while meeting stability requirements in the field. To evaluate the performance of the novel NPRW configurations, a numerical modeling was conducted considering different well diameters and well spacings and their performance was compared taking into account the number of wells and the mass of the reactive material. The comparison results showed that the sawtooth configuration was more practical than a line of wells. The performance curve of NPRWs with the saw-toothed configuration was constructed from the relationship between the contaminant removal and configuration components (diameter and spacing of the well). This can be used to predict the contaminant removal performance of NPRWs with a sawtooth array.


Energies ◽  
2021 ◽  
Vol 14 (23) ◽  
pp. 8036
Author(s):  
Ruud Weijermars ◽  
Miao Jin ◽  
Nur Iman Khamidy

This study provides a workflow and preliminary estimations of the estimated ultimate recovery (EUR) volumes for natural gas and condensate liquids in the Tuwaiq Mountain Formation, the principal target in the Jafurah Field development project in Saudi Arabia. The strategic need for the field development is reviewed and the field characteristics are outlined based on public data sources complemented with data from analogous reservoirs. The target zone in the Jafurah Basin is a carbonaceous shale, being developed with up to 10,000-ft-long multistage-fractured laterals with 30 ft perforation cluster spacing and an assumed typical 1250 ft well spacing. The field will come on stream in 2024, when the gas-gathering pipeline system, natural gas processing plant, and underground gas storage facilities will all be in place. The range of uncertainties in the key reservoir parameters is taken into account to estimate preliminary EUR volumes (P90, P50, and P10) for both gas and condensates. Based on the present and prior EUR estimations, it can be concluded that the Jafurah Basin comprises one of the largest unconventional field development projects outside of North America.


2021 ◽  
pp. 25-51
Author(s):  
Wolfgang Kinzelbach ◽  
Haijing Wang ◽  
Yu Li ◽  
Lu Wang ◽  
Ning Li

AbstractStarting in the 1990s, China has been issuing regulations and policy rules related to groundwater management and pumping control on both national and provincial levels. These policies include the requirement of permits for well drilling, a well spacing policy, pumping quota management, water resources fee collection, setting of irrigation water prices, a water rights system, water markets, and more.


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