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Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate. As reported in mid-2000, natural gas produced from shale in the US has grown to be approximately 1.6% (0.3 Tcf annually) of total gas production.
Although reserves estimates for known accumulations historically have used deterministic calculation procedures, the 1997 SPE/WPC definitions allow either deterministic or probabilistic procedures. Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Deterministic calculations of oil and/or gas initially in place (O/GIP) and reserves are based on best estimates of the true values of pertinent parameters, although it is recognized that there may be considerable uncertainty in such values.
Summary In a previous work, we introduced a three-parameter scaling solution that models the long-term recovery of dry gas from a hydrofractured horizontal well far from other wells and the boundaries of a shale reservoir with negligible sorption. Here, we extend this theory to account for the contribution of sorbed gas and apply the extended theory to the production histories of 8,942 dry-gas wells in the Marcellus Shale. Our approach is to integrate unstructured big data and physics-based modeling. We consider three adsorption cases that correspond to the minimum, median, and maximum of a set of measured Langmuir isotherms. We obtain data-driven, independent estimates of unstimulated shale permeability, spacing between hydrofractures, well-drainage area, optimal spacing between infill wells, and incremental gas recovery over a typical well life. All these estimates decrease to varying extents with increasing sorption. We find that the average well with median adsorption has a permeability of 250 nd, fracture spacing of 16 m, 30-year drainage length of 79 m, and a 30-year incremental recovery of 67%. Introduction Since 2012, the Marcellus Shale has been by far the most productive US shale play. Producing 25% of the total US dry natural gas, the Marcellus Shale currently produces at least three times more natural gas than any other major US shale play, including, in order of decreasing production, the Permian, Haynesville, Utica, Eagle Ford, Barnett, Woodford, Fayetteville, and Antrim shales (Figure 1). This high productivity has attracted significant attention from developers. The majority of drilling activities have taken place in two sweet spots: northeastern Pennsylvania, which primarily contains dry gas, and southwestern Pennsylvania and northern West Virginia, which produce liquid-rich gas (Popova 2017). Since leading US shale-gas production for the first time in 2012, the Marcellus Shale currently produces three times more than the Permian Basin, the runner-up shale-gas producer. Given how important Marcellus is to the US economy and energy security, it seems worthwhile to comb through the available production data and attempt to extract key information from the wells that are active and productive.
McClure, Mark (ResFrac Corporation) | Picone, Matteo (ResFrac Corporation) | Fowler, Garrett (ResFrac Corporation) | Ratcliff, Dave (ResFrac Corporation) | Kang, Charles (ResFrac Corporation) | Medam, Soma (ResFrac Corporation) | Frantz, Joe (ResFrac Corporation)
Hydraulic fracturing and reservoir simulation are used by operators in shale to optimize design parameters such as well spacing, cluster spacing, and injection schedule. In this paper, we address'freqently asked questions' that we encounter when working on hydraulic fracture modeling projects with operators. First, we discuss three high-level topics: (1) data-driven and physics-based models, (2) the modeling workflow, and (3) planar-fracture modeling versus'complex fracture network' modeling. Next, we address specific technical topics related to modeling and the overall physics of hydraulic fracturing: (1) interrelationships between cluster spacing and other design parameters, (2) processes affecting fracture size, (3) fracture symmetry/asymmetry, (4) proppant settling versus trapping, (5) applications of Rate-Transient Analysis (RTA), (6) net pressure matching, (7) Initial Shut-In Pressure (ISIP) trends along the wellbore, and (8) the effect of understressed/underpressured layers. We discuss practical modeling decisions in the context of field observations.
Gas production from shale formations is growing, especially in the USA. However, the origin of shale gases remains poorly understood. The objective of this study is to interpret the origin of shale gases from around the world using recently revised gas genetic diagrams. We collected a large dataset of gas samples recovered from shale formations around the world and interpreted the origin of shale gases using recently revised gas genetic diagrams. The dataset includes >2000 gas samples from the USA, China, Canada, Saudi Arabia, Australia, Sweden, Poland, Argentina, United Kingdom and France. Both free gases collected at wellheads and desorbed gases from cores are included in the dataset. Shale gas samples come from >34 sedimentary basins and >65 different shale formations (plays) ranging in age from Proterozoic (Kyalla and Velkerri Formations, Australia) to Miocene (Monterey Formation, USA). The original data were presented in >80 publications and reports. We plotted molecular and isotopic properties of shale gases on the revised genetic diagrams and determined the origin of shale gases. Based on the distribution of shale gases within the genetic diagram of δ13C of methane (C1) versus C1/(C2+C3), most shale gases appear to have thermogenic origin. The majority of these thermogenic gases are late-mature (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) and mid-mature (associated with oil generation, e.g., Eagle Ford Formation, USA). Importantly, shales may contain early-mature thermogenic gases rarely found in conventional accumulations (e.g., T⊘yen Formation, Sweden and Colorado Formation, Canada). Some shale gases have secondary microbial origin, i.e., they originated from anaerobic biodegradation of oils. For example, gases from New Albany Formation and Antrim Formation (USA) have secondary microbial origin. Relatively few shale gases have primary microbial origin, and they often have some minor admixture of thermogenic gas (e.g., Nicolet Formation, Canada and Alum Formation, Sweden). Two other revised gas genetic plots based on δ2H and δ13C of methane and δ13C of CO2 support and enhance the above interpretation. Although shales that contain secondary microbial gas can be productive (e.g., New Albany Formation, USA), the resource-rich, highly productive and commercially successful shale plays contain thermogenic gas. Plays with late-mature thermogenic gas (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) appear to be most productive.
Lu, Mingjing (China University of Petroleum, Colorado School of Mines) | Su, Yuliang (China University of Petroleum) | Wang, Wendong (China University of Petroleum) | Zhang, Ge (Xianhe Oil producing Plant, Shengli Oilfield, Sinopec)
Refracturing treatment are performed since stimulation effect won't last for entire life. Screening wells for refracturing needs a systematic analysis of huge amounts of data. With literature review, it is obviously that there are many factors controlling the success of refracturing and factors may vary in different oilfields. Proper factors and data processing are the primary principle in candidate selection. The Integrated Multiple Parameters (IMP) method is presented to provide assists in selecting candidate wells.
After deeply researching over 200 restimulated wells, all factors thought to be related with success of refracturing are listed and analyzed, results show that single factor may have great influence on restimulation but no significant patterns can be obtained since too many factors making things complicated. The IMP method proposes five parameters which are all integrated by those single factors. It is emphasized that all parameters have physical or engineering meanings which makes it easier to quantify their correlation in refracturing. Besides, all the parameters are dimensionless which makes it easier for using in mathematical models and statistical analysis.
The five dimensionless parameters are developed considering the most important aspects of candidate wells selection which are showed as followed: fracture reorientation, well completion, reservoir depletion, production decline, oil-water well connectivity. Parameters are calculated for all the restimulated wells to dig into their correlation with the outcomes of refracturing. A simple decision model is built to help with screening wells for refracturing. Results shows that it is more executable to evaluate and predict the success of refracturing with these dimensionless parameters. Fracture reorientation parameter is the primary one to be considered since it leads to fracture reorientation which brings significant production increment. Then two types of potential wells are picked: (a) wells with dissatisfied initial well completion, low production decline rate and high oil-water connectivity parameter; (b) wells with satisfied initial well completion, high well completion parameter, low production decline parameter, reservoir depletion parameter and low oil-water connectivity parameter for wells that are not easy for fracture reorientation. Wells selected are proved to be refracturing potential which verify the reliability and accuracy of IMP method.
The IMP method is an improved approach integrating most of the important factors which makes candidate selection much more predictable and it succeeds in screening out more than 80% of the potential wells in field test. Also, it can be applied widely in different oilfields since all the parameters are dimensionless. By combining with some mathematical methods such as neural networks, it can even predict increment of the restimulation treatment.
Shale reservoirs contain predominantly micro and mesopores (<50 nm), within which gas is stored as free or adsorbed gas. Due to the ultra-small pore size, multiple transport mechanisms coexist in shale reservoirs, including gas slippage, Knudsen diffusion of free gas and surface diffusion of adsorbed gas. In this work, we propose a new transport model, valid for all ranges of Knudsen number, which combines all transport mechanisms with different weighting coefficients. To quantify the effects of influence factors, we introduce the compressibility factor for real gas effect and effective pore radius for gas adsorption and stress dependence. The model is proven to be more accurate than existing models since the deviation of the analytical solution of our model (3%) from published molecular simulation data is lower than that of existing models (10~20%). Based on this model, we compare (1) the contribution of each transport mechanism to gas transport in pores of different radii, (2) shale permeability measured in laboratory and at reservoir conditions, and (3) permeability of nanopores and natural fractures. It is found that gas transport is dominated by gas slippage and surface diffusion when the pore radius is over 10 nm and below 5 nm, respectively. Knudsen diffusion only becomes significant when the pore radius is between 2 and 25 nm and pore pressure is below 1000 psi. Furthermore, laboratory measurements usually over-estimate shale permeability. We also propose a promising enhanced gas recovery method, which is to open and prop up closed natural fractures using micro size proppants.
Yan, Xia (China University of Petroleum (East China)) | Huang, ZhaoQin (Heriot-Watt University) | Yao, Jun (China University of Petroleum (East China)) | Li, Yang (China University of Petroleum (East China)) | Fan, Dongyan (Sinopec) | Sun, Hai (China University of Petroleum (East China)) | Zhang, Kai (China University of Petroleum (East China))
After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.
Qinghai, Yang (Research Institute of Petroleum Exploration & Development) | Siwei, Meng (Research Institute of Petroleum Exploration & Development) | Tao, Fu (Research Institute of Petroleum Exploration & Development) | Yongwei, Duan (Oil and Gas Engineering Research Institute) | Shi, Chen (Oil and Gas Engineering Research Institute)
CO2 waterless fracturing is a novel waterless fracturing technology. CO2 exists in the reservoir with supercritical state, and its fracturing stimulation mechanism is very different from that of water-based fracturing. This paper studies the physical and chemical properties of supercritical CO2 and reservoir adaptability of CO2 waterless fracturing.
Supercritical CO2 has the advantages of good fluidity and strong penetrability, which avail to form a complex network fractures. Through miscible phase with crude oil, absorption gas displacement, and reservoir energy enhancement, production and ultimate recovery are further improved. While the liquid CO2 has the disadvantages of poor proppant carrying capacity, high friction and low fracture opening. Based on CO2 waterless fracturing practices in Jilin oilfield, this paper summarizes physical parameters, operation effect and production situation of all wells, analyzes the main factors influencing productivity, and puts forward a set of well and layer selection methods of waterless CO2 fracturing.
Under the condition of existing CO2 thickening and resistance reducing technology, the selection of wells and layers is mainly carried out in 6 aspects. (1) Because the filtration of CO2 fracturing fluid is strong, the permeability of target reservoir should be lower than 5md in order to ensure stimulation effect of remote area. (2) CO2 can react with water and divalent metal ions to produce carbonate sediments to block existing pores and reduce reservoir permeability, so it is better for low water-bearing reservoirs. (3) Frictional resistance of CO2 is 1.9 times as that of conventional guar gum, so the target layer should be 3000m or shallower to reduce frictional pressure drop. (4) Energy increasing effectiveness of unit volume of CO2 is 1.9 times as that of slick-water, which is more suitable for stimulating undercompacted reservoirs. (5) There is no water phase in CO2 fracturing fluid, suitable for stimulating strong water-sensitive reservoirs. (6) CO2 is easy to dissolve in crude oil and greatly reduces its viscosity, which is suitable to stimulate heavy hydrocarbon reservoir.
Adopting above well and layer selection principles, CO2 waterless fracturing were implemented in 6 wells in 2017, and the key parameters, such as success ratio, sand adding amount, production capacity post-fracturing were comprehensively promoted, which effectively supported CO2 waterless fracturing development practices of unconventional reservoirs.
The CO2 waterless fracturing, just as its name implies, is a fracturing technique using CO2 as the fracturing fluid. During the operation, proppants are mixed with liquid CO2 under pressurized conditions, with the help of the customized blending apparatus, and the mixture is then injected into the wellbore to break the reservoir formation, create artificial fractures, and place proppants to avoid fracture closure after depressurization. The CO2 blending apparatus is a high-pressure sealed container, in which proppants are put inside prior to the fracturing operation. The blender connects the piping system, and is capable of mixing the proppant and CO2 liquid stream, and driving the mixture into the high-pressure fracturing pump.