Frac Fluid Research Articles

Crucial Development Technologies for Volcanic Hydrocarbon Reservoirs: Lessons Learned from Asian Operations

Oil and gas reservoirs in volcanic rocks are a particular type of unconventional reservoir and present unique challenges for exploration and production engineers. To help the oil industry understand volcanic reservoirs and solutions to complex development problems, we reviewed their key engineering technologies as well as their geological characteristics. The distinctive geological characteristics of volcanic hydrocarbon reservoirs are strong heterogeneity, low porosity and permeability, complex fracture systems, etc. The volcanic reservoir rock types in order of hydrocarbon abundance are basalt (38.5%), andesite (15.9%), volcaniclastic (12.1%), and rhyolite (11.5%). The porosity ranges from 0.1 to 70%, and permeability ranges from 0.0007 to 762 md. In some commercially developed volcanic reservoirs of China, the average porosity is 7.7–13%; the average permeability is 0.41–3.4 md. Engineers have applied a variety of adapted technologies to produce volcanic reservoir economically. Horizontal wells can increase production and reserves by 4–6 times those of vertical wells, and longer wells are preferred. Specialized hydraulic fracturing techniques are suggested, including small or mixed proppant size, second HF treatment after proppant slugging, high-viscosity frac fluid with high-temperature resistance, special fluid loss reducer, high pump pressure, Extreme Overbalance Perforating, limited-entry fracturing, matrix acidizing, etc. Water control measures include producing below critical rates, partial perforation or penetration, controlling hydraulic fracture height, using horizontal wells, implementing complete cementing job, etc. Well productivity evaluation should be conducted to understand well performance and appropriately allocate production rates among wells, using the modified AOF method and other productivity prediction models considering breakdown fracture gradient, gas slippage effect, non-Darcy effect, etc. Well sites need to be selected based on recognizing profitable lithologies, lithofacies, high porosity and permeability, relatively developed fracture systems, thick net pay zones, etc. The critical questions for the industry are how to enhance volcanic reservoir recovery with more efficient and economic hydraulic fracturing and water control techniques. This is one of the first papers systematically summarizing the engineering technologies and unique solutions to develop volcanic reservoirs. Further and more complete reviews can be carried out in the future, and more novel and effective techniques can be explored and tested in the field.

Research on Calcium Chloride Weighted Polymer Fracturing Fluid for Ultra Deep and High Stress Reservoirs

To enhance fracture and conversion effects in deep and ultra-deep oil and gas reservoirs, a low-cost polymer-weighted fracturing fluid technique was developed using industrial calcium chloride as a weighting agent and synthesizing a polyacrylamide polymer, FA-31, with a molecular weight of 4-6 million, as a thickening agent. In addition, we have developed an amphoteric metal crosslinker capable of forming multiple hydroxyl bridges with crosslinked groups, a novel XG160 high-efficiency gel breaker, and a complete set of stress corrosion inhibitors. The optimal concentration for the use of calcium chloride dihydrate is 46% and the density of aqueous solution is 1.35 g/cm3. The developed highly salt-resistant polymer dissolves rapidly in a high-density calcium chloride salt solution. The industrial calcium chloride gel formed by polymer has a maximum temperature resistance of 170 °C, a shear rate of 170 s-1 for 120 min, and a viscosity of more than 100 mPa·s. It also performs well in high-temperature suspension sand conditions. The viscosity of the gel breaker is less than 5 mPa·s. Laboratory tests have shown a core damage rate of about 20% and no stress corrosion cracking. The on-site application of liquid preparation and construction has been smooth, achieving the desired effect of reducing construction pressure. For example, when refurbishing a 7500 m reservoir, the building pressure can be reduced by 10-20 MPa. On-site testing of calcium chloride-weighted frac fluids has confirmed their effectiveness as a cost-effective alternative to conventional weighted frac fluids, providing a viable solution for the conversion of deep, ultra-deep, high-stress oil and gas reservoirs.

The impact of fracture network on CO2 storage in shale oil reservoirs

CO2 flooding or huff-n-puff has been recognized as a practicable EOR and carbon storage method. Since the shale rocks are very tight, it is preferable to inject CO2 into shale reservoirs for storage to avoid CO2 leakage. In this paper, we investigated the CO2 storage capacity in a hydraulically fractured horizontal well in Xinjiang shale oil reservoirs. A comparison of CO2 storage capacity was performed by stimulating different fracture networks. Three types of fracture network were created: 2 clusters, 3 clusters and 6 clusters in per 90-m stage. In the multi-cluster hydraulic fracturing treatment, injected frac fluids and proppants in each stage remain the same. It is found that perforating more clusters in a stage results in a shorter length of hydraulic fractures. However, for the case of 30 m cluster spacing, a considerable portion of the created fracture length does not contribute to production. Oil recovery factor with 15 m fracture spacing is greater than that of 45 m and 30 m. In the case of CO2 injection for EOR purpose, this process has less pronounced effect on CO2 storage. However, fracture network plays an important role for CO2 storage in depleted reservoirs. Smaller fracture spacing provides a larger SRV near the horizontal wellbore which is critical to CO2 storage. The SRV near the wellbore for 15-m fracture spacing is larger than that of 30-m and 45-m, which is critical to improving horizontal well deliverability. This study will provide a perspective on improving cluster efficiency and increasing CO2 storage capacity in horizontal wells.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability, and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition. After multi-stage and multi-cluster hydraulic fracturing, a complex fracture network is formed, and a large volume of frac fluid is stored within the fracture network. During shut-in, imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure, and the formation pressure builds up in the shale reservoir. On basis of the characteristics of shale oil reservoir, we establish a model of imbibition during fracturing injection and shut-in by coupling oil–water two-phase flow and saline ion diffusion in the hydraulic fractures (HFs) network, natural fractures (NFs) and matrix system under the action of capillary force and osmotic pressure. The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively, which avoids the problem of a large amount of computation of seepage within the complex fracture. Then, the discrete fracture network (DFN) model and the multiple continuum model are solved with the finite element method, and it is verified in flow field, saturation field and concentration field that the models are accurate and reliable. We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume. Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models. It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference, capillary force and osmotic pressure. The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume. The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference. If imbibition equilibrium is reached, low initial water saturation, strong rock compressibility, high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir. The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume. Leakoff equilibrium occurs slightly earlier than imbibition equilibrium. The imbibition equilibrium time is mainly affected by reservoir permeability and NF density. The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process. The stimulated reservoir volume (SRV) mainly affects frac fluid imbibition exchange in the shut-in process.

Stability of Natural Fractures under Disturbance of Hydraulic Fractures in Shale Reservoirs

Activating the natural fracture (NF) during hydraulic fracture (HF) propagation is a dominant factor for forming the complex fracture network in shale reservoirs. On basis of Renshaw and Pollard’s criterion for fracture intersection, we simulate the NF stability under dynamic disturbance of HF propagation in shale reservoirs with the cohesive zone model in ABAQUS and analyze the effects of various factors on the NF stability. The results show that activation of the NFs in shale hydraulic fracturing is controlled by NF length, NF density, intersection angle between the NF and the HF, horizontal principal stress difference, frac fluid viscosity, and injection rate. During HF propagation, the NF shorter than 0.2 m is less likely to be activated, and those longer than 0.5 m are more likely to be activated. As the NF density increases, not all NFs are activated. The NF at an approach angle larger than 10° is more likely to be activated. The NF is more likely to be activated under the low stress difference, and the NF cannot be activated when the stress difference is higher than 10 MPa. Both frac fluid viscosity and injection rate have effects on activation of NFs, and the NF is more likely to be activated by higher viscosity frac fluid and under higher injection rate. The results provide reference for fracture network stimulation in shale reservoirs.

Numerical investigation of the factors affecting the cement sheath integrity in hydraulically fractured wells

The current industrial practice calls for wells to be hydraulically fractured in as many as 50 stages, depending on the formation. The integrity of the cemented wellbore sections around the perforations has been a major concern in most hydraulically fractured wells. In this paper, we have conducted a comprehensive numerical modelling study to understand the possible impact of hydraulic fracturing operation on the integrity of the cemented wellbore sections, especially around the perforations where the fracture fluid is injected. A numerical model allowing full coupling of solid/liquid flow has been adopted to simulate the fracturing fluid injection and the resultant deformation of cemented casing sections around the perforations. Field data from a hydraulically fractured deep shale gas well in China were used to demonstrate the impact of the operational variables on the integrity of the cemented wellbore section. We also studied the influence of fracture fluid injection pressure, mechanical properties of the cement, casing and the reservoir, perforation azimuth, and fracture fluid viscosity on the cement sheath failure. Simulation results have shown that the cement sheath failure at the cement-casing interface may occur in the form of debonding in the radial direction. The cement debonding occurring at the casing-cement interface due to high frac fluid injection pressure, would be one of the main reasons for the poor hydraulic fracturing job performance commonly observed in shale gas wells. Following conclusions can also be drawn from simulation results: 1) Injection pressure has an important impact on the cement debonding. For the specific reservoir conditions investigated in this paper, to avoid cement debonding, the injection pressure should be no more than 75 MPa; 2) Use of a casing with a larger elasticity modulus and cement with lower elasticity modulus and lower permeability are conducive for improved cement bonding quality; 3) For a shale gas reservoir with lower permeability, these requirements for the casing and cement should be even stricter. Resultsof this study can be useful for optimum selection of the limiting pump pressure, cement and casing properties, and the perforation azimuth to be used for the design of a successful hydraulic fracturing job.

Foam Based Fracturing Fluid Characterization for an Optimized Application in HPHT Reservoir Conditions

Water-based fracturing fluids are among the most common fluid types used in hydraulic fracturing operations. However, these fluids tend to cause damage in water-sensitive formations. Foam comprises a small amount of base fluid, and compressible gas such as carbon dioxide and nitrogen has emerged as a more ecologically friendly option to fracture such formations. Foam is an attractive option since it has a low density and high viscosity. The applicability of foamed frac fluid is characterized by foam stability and rheology, encompassing the viscosity and proppant carrying ability. The foam quality, pressure and temperature affect the foam rheology. Generally, foam viscosity and stability increase with pressure but decrease when the temperature increases. Hence, it is essential to preserve foam stability in high pressure and high temperature (HPHT) reservoir conditions. The addition of nanoparticles could increase the thermal stability of the foam. This article provides the basis of foam-based fracturing fluid characterization for an optimal application in HPHT reservoir conditions. Then, focusing on improving thermal stability, it reviews the research progress on the use of nanoparticles as foam stabilizing agent. This paper also sheds light on the literature gaps that should be addressed by future research.

Experimental Investigation on Proppant Transport Behavior in Hydraulic Fractures of Tight Oil and Gas Reservoir

Proppant concentration and fracture surface morphology are two significant fractures that can affect proppant transport and deposition behavior especially in tight and oil and gas reservoirs. This paper proposed a new set of similarity criteria for proppant experimental design by incorporating proppant concentration and fracture roughness. Based on the proposed criterion, proppant transport experiments in hydraulic fractures of tight oil and gas reservoirs were conducted to explore the proppant placement behavior and identify the key parameters that affected the fracture propping efficiency. Results showed that the proposed similarity criterion can be used to evaluate the onsite proppant transport behavior and optimize hydraulic fracturing parameters. Results showed that the fracture placement efficiency of LD C7 tight oil reservoir is mainly affected by sand ratio and fracturing fluid viscosity. The sand ratio in the LD C7 tight oil reservoir should not be less than 8%, and the optimal carrying fluid viscosity is 5 mPa s. The proppant placement efficiency of the SLG H8 tight gas reservoir is mainly affected by the displacement rate and frac fluid viscosity. The displacement rate of SLG H8 tight gas reservoir should not be less than 3.5 m3/min, and the optimal carrying fluid viscosity is 15 mPa s.

Tunnel Hydraulic Fracturing evaluation and comparing with conventional hydraulic fracturing computation

Tunnel Hydraulic Fracturing is one method of well fracturing operation which generates tunnel in proppant filled fractured rock, near wellbore. The tunnels are in-between packs of proppant. The occurrence of tunnel is caused by certain pumping technique during hydraulic fracturing operation. Frac fluid is pumped continuously, along with proppant is pumped intermittently. These tunnels generate high conductivity media in the fracturing geometry. The subject well was initially flow tested intermittently with 95% to 100% oil cut. The permeability from log correlations is 8 mD, with 1824 Psireservoir pressure, from surrounding wells. Rock mechanic and type of stresses were evaluated to determine tunnel fracturing candidacy. After designing Tunnel Fracturing Design, operationally Pre-fracturing test sequences was executed, which is followed by re-design and operation of Mini frac test. The final design is followed by performing pulsed Mainfrac. The Tunnel Fracturing geometry was computed by service provider software, and the Productivity Index PI by spreadsheet. The Conventional Fracturing and its PI was computed by using spreadsheet. The Tunnel Hydraulic FracturingPI was as much as 4.22 while Conventional Fracturing was 2.05.

Биодеструкция гуаровой камеди в жидкости гидроразрыва пласта под действием ферментных препаратов базидиальных грибов

Guar gum is a polymer that is widely used as a gelling agent for technological liquids in the petroleum industry. In this paper, we have studied the potential for the environmentally friendly biodegradation of guar gum by enzymes of basidiomycetes for efficient disposal of oil industry wastes. For the first time, we compared the enzymatic activity towards guar gum of seven basidiomycete strains, namely Trametes hirsuta MT-24.24, Lactarius necator, Trametes hirsuta MT-17.24, Schizophyllum commune MT-33.01, Fomes fomentarius MT-4.05, Fomitopsis pinicola MT-5.21, and Trametes versicolor It-1. This comparison showed that the preparation based on Fomitopsis pinicola MT-5.21 fungal mycelium at a concentration of 0.05% provides the most efficient decomposition of a frac fluid containing guar gum. By varying the enzyme concentration in this fluid it is possible to control the decrease in its viscosity over time. The developed enzyme preparation is an efficient and environmentally friendly guar gum biodegradant and can be used to process waste fracturing fluids based on polysaccharides in order to reuse water resources. Key words: biodegradants, basidiomycetes, guar gum, enzymatic hydrolysis, enzyme destructors, fracturing fluids. Funding - The work was financially supported by the National University of Oil and Gas "Gubkin University" (Internal grant no. 120720 "Development of New Biotechnological Methods and Materials for Environmental Protection and Biomedicine").

Insights into productivity drivers for the Niobrara-equivalent horizontal play in the Piceance Basin, Colorado

Limited horizontal drilling has occurred within the Niobrara-equivalent section of the Mancos Shale in the Piceance Basin, and the results from individual wells are highly variable. Prior studies have suggested that thermal maturity and completion techniques were the primary drivers for the observed production trends, but further analysis of well results indicates there are more variables at play. This study leveraged a comprehensive data set from the Piceance Basin, including core analyses, pressure data, and drilling and completion methods to provide additional context for the production results. From this analysis, several key trends were identified. North/south variations in thermal maturity were confirmed, as well as additional trends were identified revealing later exhumation south of the Rangely fault system resulted in significant depressurization, particularly in the western Piceance Basin. The semi-regional depressurization was the result of decrease in overburden pressures that allowed vertical migration of hydrocarbons out of the Mancos Shale. In addition to the semi-regional depressurization, there were more local depressurization events that resulted from faulting in areas such as the Orchard Unit in the southern Piceance Basin where thrust faults allowed hydrocarbons to migrate vertically into overlying formations. Northwest to southeast production trends are present in the southern Piceance Basin and are interpreted to reflect structurally undeformed areas based on high formation pressures and better producing horizontal wells. Parent-child effects have been observed locally and are linked to lower initial production rates and faster decline rates. The northern Piceance Basin exhibits higher reservoir pressure in the liquids window than was observed to the south due to the relatively low degree of exhumation and/or faulting in areas where horizontal Niobrara wells were drilled. Horizontal well results in the northern Piceance Basin have been mixed, largely due to inefficient completion strategies. By comparing the northern Piceance Basin wells with similar horizontal Niobrara wells in the Powder River Basin of northeastern Wyoming, it is concluded that drilling into the over-pressured liquids rim and utilizing slickwater frac fluid with friction reducer and 100 mesh sand will yield improved economic results over those obtained so far in the Piceance Basin. Though relatively few laterals have been drilled in the Piceance Basin Niobrara play, the basin has great future potential.

How will treatment parameters impact the optimization of hydraulic fracturing process in unconventional reservoirs?

Hydraulic fracturing is a very complex process that has not yet been fully understood. Furthermore, the number of stages, length of fracture clusters in each stage, proppant and fracturing fluid compatibilities, optimum spacing length, proppant transport and placement, proppant and frac-fluid compatibility, and optimum spacing are some of the challenges inhibiting successful application of this technique across the world. In this study, we present the impact of fracture-cluster lengths, proppant types and sizes, proppant densities, frac fluid types, fluid viscosities, and injection rates on hydraulic fracturing process. Firstly, we developed a stress profile to determine initiation location and orientation of the hydraulic fractures, and subsequently created the geological layering in the zone of interest. We grouped our investigations into 5 case studies, followed by developing an efficient hydraulic fracturing design approach, and we determined the optimal treatment to achieve maximum recovery. Our results show that fracture clusters with optimal lengths will provide optimized hydraulic fracture treatment. In addition, high-strength proppants is efficient for shale formations with closure stress exceeding 5000 psi to achieve optimum fracture conductivity and fracture half-length. Furthermore, we observed the high-density proppant produced greater fracture lengths and lower dimensionless fracture conductivity (CFD), while the low-density proppant produced greater effective propped-fracture lengths and higher CFD. In some of the cases investigated, we observed that stress shadowing and interference can hinder fracture growth, eventually led to a collapse of some fractures. Our results provide valuable critical decision-making insight for optimizing hydraulic fracturing process in unconventional reservoirs across the world.

A novel workflow for water flowback RTA analysis to rank the shale quality and estimate fracture geometry

Recently, flowback data analysis enabled us to evaluate important fracture parameters including fracture conductivity and volume in unconventional reservoirs. To perform the analysis, diagnostic plots, straight-line techniques, and history-matching techniques have been used. Immediate water and gas production usually occurs on flowback in shale gas wells. In this paper, a novel workflow is developed for the analysis of water flowback data and the early-time production of shale gas wells. This analysis then helps to define the movable water and the applicability of the soaking process on these wells.Rate transient analysis (RTA) combined with decline curve analysis (DCA) were used to analyze different shale gas wells. Effective fracture volume and geometry were calculated from the RTA analysis. The estimated ultimate water recovery (EURw) was calculated from DCA. The calculated original water-in-place (OWIP) and the EURw were compared to the injected fracturing fluid. The impact of the soaking process on the well performance was studied.Results showed that in high-quality shale wells, with no movable formation water, gas kicked off early. OWIP was equal to the total injected water volume, and boundary dominated flow (BDF) regime was observed with no transient period. The performance of these wells improved with soaking.On the other hand, in low-quality shale wells, initial formation water saturation was higher than the connate water, and water production was from both the frac fluid and formation water. Consequently, gas kicked off later and transient flow regimes were observed. Transient flow regimes were used to estimate the fracture stimulated area. In this case, however, soaking had a negative impact on the performance as the movable water saturation was high.Honoring the flowback data can be used to estimate the fracture geometry and judge the quality of the shale formation and its validity for the soaking process.

Geochemical identification of the source and environment of produced water from CBM wells and its productivity significance: examples from typical CBM wells in eastern Yunnan and western Guizhou

The geochemical information of produced water from coalbed methane (CBM) wells is abundant in geological significance. Based on the conventional ions, hydrogen and oxygen isotopes (δD and δ18O) and trace element tests of 27 produced water samples from CBM wells, the geochemical identification of the source and environment of produced water from CBM wells and its productivity significance have been analysed. The following conclusions have been drawn: CBM produced water can be divided into three categories, namely, polluted water from frac fluids, polluted surface water and formation water. The formation water has low Cl- concentration, low total dissolved solids (TDS) concentration, and light δD and δ18O. The water polluted by frac fluid has high Cl- and TDS concentrationt, and heavy δD and δ18O. The polluted surface water has high SO42- and light δD and δ18O. CBM groun dwate r environments can be divided into confined and unconfined systems. The confined system is characterized by low Na+/Cl- value, high (Cl- - Na+)/Mg2+ value, a general absence of SO42-, high Sr and Ba and low F. The unconfined system is characterized by high Na+/Cl- value, low (Cl- - Na+)/Mg2+ value, low SO42-, low Sr and Ba and high F. Constructing a cross plot with the new D drift index (d') value and Cl- concentration can further identify four types of source-water environments: an unconfined formation water system, an unconfined surface water system, a confined system heavily polluted by frac fluids, and a confined system only slightly polluted by frac fluids. The unconfined system often produces more formation water and has high CBM production. The confined system often produces water more heavily polluted by frac fluids and is low in CBM production. The fitting formulas of hydrochemical productivity have been established for daily CBM and water production of CBM wells.

Research and application on wellbore integrity technology for Integration of Oil Recovery, Well Completion and Drilling

Huabei oilfield has entered the middle and late periods of the development, and a series of problems such as casing damage, casing deformation, restricted measures and eccentric wear of staff and tube are gradually exposed in the development process[1,2], which affect the development benefit of oilfield, and the wellbore integrity is closely related to the development benefit. Therefore, in order to ensure the qualified wellbore conditions, huabei oilfield put forward the design concept of “Integration of Oil Recovery, Well Completion and Drilling”, the engineering design system of multi-professional coordinated and unified “Integration of Oil Recovery, Well Completion and Drilling” are constructed, the optimization design of drilling trajectory, casing and frac fluid system was carried out. The application shows that the design prolonged the life cycle of oilwell effectively, which of great significance for single well productivity improvement and benefit development.

Roles of Surfactants during Soaking and Post Leak-Off Production Stages of Hydraulic Fracturing Operation in Tight Oil-Wet Rocks

Many experimental studies have been conducted in the recent past to assess the inclusion of different types of surfactant in a frac fluid in hydraulic fracturing of low-permeable formations. These lab studies either corresponded to spontaneous imbibition testing using Amott cells or dynamic core-flooding tests to assess the hydrocarbon permeability after the invasion of the frac fluid. Both these tests have been considered independently by different authors but have not been analyzed as one holistic approach to assess the oil recovery potential of a surfactant. It is prudent to understand the superiority of the specific interfacial mechanism of the surfactant that correlates to the best-case scenario of oil recovery by considering both the tests that lead to leak-off and follow the leak-off of frac fluid into the matrix. In this experimental study, two tests related to soaking and production processes are conducted simultaneously using surfactants with different interfacial properties of interfacial tensi...

Characterization of Organic Matter in Water from Oil and Gas Wells Hydraulically Fractured with Recycled Water

Liquid chromatography quadrupole time-of-flight mass spectrometry was performed to understand how frac fluid with recycled water (RWA) and frac fluid with fresh water (FWA) compare when subjected to downhole temperature and oxidation conditions. Ethylene oxide and propylated glycol functional units were quantified from both RWA and FWA. Qualitative analysis was performed using Agilent qualitative analysis software B.06.00 based on the exact mass of the chemical compound. Acetone, aldol, alkoxylated phenol formaldehyde resin, diethylbenzene, dipropylene glycol, d-Limonene, ether salt, ethylbenzene, n-dodecyl-2-pyrrolidone, dodecylbenzenesulfonate isopropanolamine, polyethylene glycol, and triethylene glycol were detected in FWA and RWA samples. In the van Krevelen diagram, FWA and RWA show a low degree of oxidation and highly saturated organic compounds. Kendrick mass defect (KMD) analysis was applied using ethylene oxide and propylated glycol units. KMD analysis based on ethylene oxide was scattered between 0 and 0.1, while some KMD analyses based on the propylated glycol are close to 1. FWA had an average carbon number of 32.3 and double bond equivalent (DBE) of 9.8 while RWA had average carbon number of 31.5 and DBE of 9.5. RWA contained predominantly C21-C40 compounds, while FWA had a higher concentration in the over C41 range.

The concept of coke based proppants for coal bed fracturing

The concept of a new type of coke-based proppant for hydraulic fracturing of coal seams for coalbed methane extraction is introduced. Our solution will facilitate gas inflow into the well due to the fact that the proppants will be resistant to embedment into the coal formation, and gas flow through porous coke grains will be possible even in the case of their partial penetration into the coal rock. Low density of the material will enable suspending the proppant particles in low viscosity frac fluids, which in turn will allow for: decreased flow resistance, minimizing water consumption and better well cleaning. Coke based proppants will allow to increase the performance of hydraulic fracturing operations in coal seams, resulting in improved efficiency of obtaining coalbed methane. The new product will be presumably suitable for stimulation treatments in other, soft rocks or even allow hydrocarbon exploitation from the formations that were previously considered as unproductive.

Hydraulic Fracture Geometry Inversion and Analysis of Influencing Factors Based on ABAQUS

Based on the finite element software ABAQUS, the three-dimensional model of fluid-solid coupling hydrofracture expansion is established, and the hydraulic fractures are retrieved according to reservoir parameters. The effects on fracture propagation are analysed, including the injection pressure, the frac fluid viscosity, the maximum and minimum principal stress and Young’s modulus of rock on fracture propagation. The results show that the maximum length and width of the fracture increase gradually with the increase of the injection pressure, but decrease with the increase of the elastic modulus. With the increase of the frac fluid viscosity, the maximum fracture length and width show two opposite trends. The maximum fracture length decreases with the increase of the viscosity, but the decreasing rate slows down gradually, showing the decreasing trend of the exponential function. However, with the increase of the viscosity, the maximum fracture width increases and the initiation pressure is not affected. When the minimum principal stress increases gradually, the maximum fracture length and width reduced gradually, and the initiation pressure also increases linearly, but the change of the maximum principal stress has no effect on the fracture initiation pressure.

A semi-analytical approach for analysis of the transient linear flow regime in tight reservoirs under three-phase flow conditions

The majority of current techniques for production data analysis of hydraulically-fractured horizontal wells only consider single- or two-phase flow conditions. Three-phase flow is expected to occur in many practical scenarios of low-permeability reservoir production when water (frac fluid and/or formation) production is occurring along with hydrocarbon phases. In this paper, a new semi-analytical method is developed to allow production data analysis of wells producing from low-permeability (tight) reservoirs exhibiting three-phase during the transient linear flow period.The proposed technique is based on the modified black oil formulation and is developed by employing the Boltzmann transformation. The modified black oil formulation comprises three highly nonlinear Partial Differential Equations (PDE's) that describe the flow of water, oil and gas in the reservoir. The use of the Boltzmann transformation allows conversion of this set of governing fluid flow PDE's to a set of Ordinary Differential Equations (ODE's) that can be easily solved using numerical techniques such as the Runge-Kutta method. In this paper, oil relative permeability under three-phase flow conditions is modelled using Stone's well-known first model.A theoretical basis for the occurrence of straight lines on a plot of 1/q vs √t for any producing phase is provided herein. The slope of the line is a function of the flowing fluid properties, and the reservoir and fracture characteristics. One important advantage of using the Boltzmann transformation is that the linear flow parameter, xf√k, can be directly estimated as a part of the solution process without the need for defining any complex pseudo-variable transformations. The results demonstrate that the relative error in xf√k estimation is generally less than 10% for different fluid models and relative permeability curves. Moreover, the simultaneous solutions of the ODE's provide the pressure and phase saturations as unique functions of the Boltzmann variable; these can be used to find relationships between pressure and phase saturations that in turn can be utilized for other rate transient analysis applications. The derived pressure-saturation relationships are in excellent agreement with numerical simulation for different three-phase relative permeability models.The significance of this paper is that a new theoretical and practical framework is introduced for the first time to analyze three-phase production data for transient linear flow under constant flowing bottomhole pressure conditions. These conditions are of practical importance for many tight production scenarios where water, in addition to hydrocarbon phases, are mobile in the reservoir. The results are validated using numerical simulation.