The development of unconventional hydrocarbons has become a significant resource, leading to growth of worldwide oil and natural gas supplies. Hydraulic fracturing has been successfully employed for unconventional oil and gas recovery for decades. In recent years, the rapid progress of technology has led to reduced gas prices and a shift in focus to liquid extraction.
However, liquid flow, both in the wellbore and channels inside porous media or fractures, experiences more resistance compared to gas, resulting in significant pressure losses in the wellbore and fractures. Reservoir productivity also becomes more complex because of relative permeability effects. Forecasting production and estimating shale reserves is still not fully understood because of the limited knowledge of flow mechanics in ultralow-permeability rock.
Many analytical, semi-analytical, and numerical models have been developed to better understand flow in ultralow-permeability rocks and hydraulic fractures. Because analytical models only apply to mostly dry gas reservoirs, numerical reservoir simulation is generally believed to be the most rigorous and accurate method for liquid-rich formations. However, the drawbacks of using reservoir simulation are substantial. Some examples include the significant data requirements, level of expertise required to set up the model, and the demanding turnaround times for meeting the design, optimization, and decision-making cycle deadlines. Also, because each engineer is responsible for a large number of wells, full-scale three-dimensional (3D) reservoir modeling is impossible for a majority of wells.
Therefore, an approach is required that is less time-consuming than detailed reservoir simulation while still being sufficiently accurate to capture the physics of the process. It should be based on numerical modeling of multiphase flow in the interconnecting system of the wellbore and fractures, with the reservoir represented by a productivity index (PI) inflow model, as well as a physics-based pressure-volume-temperature (PVT) model for phase transition and phase equilibrium. The production decline and prediction should be analyzed based on reservoir depletion, relative permeabilities, and fracture conductivities.
This paper describes a numerical fracture production model (FPM) based on the previously mentioned physics that can be used to simulate production resulting from reservoir depletion and analyze historical production data. The outcome of the model focuses on a few primary input parameters that are dedicated to predicting future production and quickly analyzing the parametric effects and economic value of fracture-stimulated condensate reservoirs. The model is validated using two commercially available software programs, as well as historical production data of an Eagle Ford play. The outputs are then used for history matching, sensitivity analysis, parameter optimization, and future production prediction.
Katsuki, Daisuke (Colorado School of Mines) | Deben, Anton Padin (Colorado School of Mines) | Adekunle, Olawale (Colorado School of Mines) | Rixon, Andrew J. (Colorado School of Mines) | Tutuncu, Azra N. (Colorado School of Mines)
SummaryA high-pressure triaxial compression cell has been utilized to study the stress-dependent permeability and dynamic elastic moduli in reservoir and seal shales. The testing assembly used is capable of characterizing tight shales in terms of permeability and ultrasonic wave velocities. The temperature was maintained at 40 oC with ±0.3 degree C of accuracy during the testing to minimize the influence of temperature disturbance on the measurements. The measurements have been carried out by increasing the net stress. The measurements have been carried out by increasing the net stress from 200 to 6,000 psi using dry nitrogen as the pore fluid. The Pierre seal shale sample contains approximately 60 percent of smectite clay, no organic composition and has higher porosity and permeability than the reservoir shale and was utilized as a reference shale for comparison. The reservoir shale is retrieved from a shale layer belonging to Eagle Ford containing 65 percent of calcite. The main components of clay of this shale is mica/illite and its mass content is 13 percent. The total organic carbon (TOC) content of the reservoir shale is 1 percent.
The experimental results indicated that the permeabilities of both reservoir and seal shales studied exponentially decrease with net stress. The stress sensitivity for the permeability of reservoir shale is three times greater than that of Pierre shale, although the permeability of reservoir shale is an order of magnitude lower than that of seal shale. The mechanism behind the stress sensitivities in shale permeability is discussed comparing stress sensitivity of the dynamic elastic properties for these shales.
Coupling pore fluid behavior and geomechanical properties of unconventional reservoir rocks is of great interest for developing reliable geomechanical models for comparing their behavior to the conventional reservoir rocks. Nano-scale complexities and heterogeneous pore distribution along with presence of various clay minerals and organic matter in reservoir shales complicate their geomechanical response changes in pore fluid pressure and other properties during completion and stimulation operations.
In nanopores, capillary pressure becomes high and promotes capillary condensation of the fluid phase (Bui et al., 2015). In addition, a change in the stress field in the reservoir rocks due to the disturbances from the drilling, hydraulic fracturing and production operations can largely affect the geomechanical properties. However, access to reliable stress-dependent permeability data in the reservoir shale formations coupled with their geomechanical behavior in the laboratory under in situ stress conditions is quite limited because of the high cost of retrieving core samples in addition to the expenses involved for their measurements.
Li, Yurong (Missouri University of Science and Technology) | Nygaard, Runar (Missouri University of Science and Technology) | Cheng, Baokai (Clemson University) | Zhu, Wenge (Clemson University) | Xiao, Hai (Clemson University)
Leakage is one of the major concerns in a geological carbon sequestration project due to the adverse environmental consequences. The main leakage risk of CO2 through a thick, low permeable cap rock is identified to be along wells, especially in sedimentary basins that have a history of oil and gas exploration and production. To pursue a robust and cost effective real-time monitoring technology for CO2 leakage risk detection along the wellbore, a permanently downhole deployed coaxial cable casing imaging system is developed and tested for various deformation modes in laboratory in this paper.
The casing imager consists of a helically wrapped coaxial cable on the outside of the casing with coaxial cable strain sensors evenly distributed along the cable. A lab-scale prototype of the casing imager was deployed on both PVC sewer pipes and steel pipes for testing on four commonly observed casing deformation modes in the oil field, including axial compression, radial expansion, bending, and ovalization. The coaxial cable strain sensors were pre-stressed and then helically wrapped and attached onto the outer wall of the pipe at a pre-determined angle with high strength epoxy. Multiple LVDTs or strain gauges were used as independent measurement of the pipe actual deformation in comparison to the casing imager measured pipe deformation throughout all the tests.
The test results demonstrated the ability of the lab-scale casing imager prototype in real-time monitoring of casing axial compression, radial expansion, bending, and ovalization, which would prove great value in evaluating wellbore integrity and providing early warnings of leakage risk that will contaminate the ground water during CO2 injection. In addition, the low cost and high robustness of the distributed coaxial cable sensors will greatly lower the downhole monitoring cost and increase the system longevity.
Leakage is one of the major concerns in a geological carbon sequestration project due to its adverse environmental impact. The safety of drinking water would be threatened by the accumulated high concentration CO2 if it is leaked into a contained environment with possible consequences such as lowered pH and increased concentration of total dissolved solids (Bacon, 2013; Little & Jackson, 2010). Each CO2 sequestration project will have its unique leakage risk assessment, but the main leakage risk of CO2 through a thick, low permeable cap rock is commonly identified to be along existing wells or through faults and fractures (Cook, 2014; Edlemann et al., 2016; Metz et al., 2005; Moreno et al., 2005). Especially in sedimentary basins that have a history of oil and gas exploration and production, the existing wells provide possible pathways for leakage of waste fluids toward the shallow subsurface and the land surface (Bois et al., 2011, 2012; Nordbotten et al., 2004; Watson & Bachu, 2007). The cement sheath as one of the primary barriers to prevent wellbore leakage and failure, its integrity begins at the cementing operation and what happens there can greatly affect the long term integrity of the well (Weideman & Nygaard, 2014). Thus, it is of great importance to monitor the downhole activities during the cementing and CO2 injection process to provide early warnings of leakage risk.
Even in the current market conditions, there's still a need for large amounts of water to conduct hydraulic fracturing, drilling, and completion operations. As millions of gallons of water are needed for each fracturing operation and with most operations occurring in water-stressed regions, the use of fresh water for oilfield applications is coming under greater scrutiny.
Water flowed back from hydraulic fracturing (flowback water) and in situ ground water brought to the surface (produced water) during production account for large volumes of “dirty” water generated by the oil industry. According to the Department of Energy (DOE), produced water accounts for an average of over 60 million barrels per day.1 This water is tainted by various chemicals and/or has natural compositions that, in most cases, render it unsuitable for human consumption, dispersion into nature, or even reuse in the oilfield. Historically, the only way to dispose of this produced water has been to re-inject it into the ground by using salt-water disposal wells.
As water conservation initiatives and the tightening of regulations concerning the use of fresh water become more prevalent, the need to come up with ways to recycle the water already “in the system” becomes more appealing. Operators requiring large amounts of water are looking to produced water for their fracing operations as a solution.
The trend to reuse produced water is being enabled by advancements in mechanical and chemical treatment techniques and the introduction of new fracturing chemical systems that accept high levels of chloride and other chemical concentrations. These technological improvements have opened the way for alternative, economically viable techniques for maximizing the reuse of water in fracturing operations.
The use of produced water makes both economic and environmental sense, as it reduces the need for fresh water and the subsequent cost of trucking and disposal. If fresh water is used for fracing operations and all the produced water is injected into the ground, operators incur trucking, disposal, and storage costs, along with costs to acquire fresh water. With an average cost of $.75/bbl for fresh water and disposal costs ranging from $.50-$2.50/bbl, it makes economic sense to reuse produced water.
Zhang, Jilin (Aramco Research Centers -Houston) | Lai, Bitao (Aramco Research Centers -Houston) | Liu, Hui-Hai (Aramco Research Centers -Houston) | Li, Hui (University of Louisiana) | Georgi, Dan (Aramco Research Centers -Houston)
Unconventional shale poses many challenges for exploitation due to the complexity in mineralogy, the presence of kerogen, laminations, and the low permeability; thus in most cases, hydraulic fracturing is needed for economic recovery. One of the most important parameters for engineers is the tensile strength of the shale reservoir rocks, which is affected by the amount of ductile vs brittle minerals, the amount of kerogen, the textures of the rock, and the saturation states. In this study we investigate the effect on the tensile strength measured from Brazilian tests of the lamination and mineral assemblage, using computed tomographic (CT) imaging and X-ray diffraction (XRD).
A group of Mancos and Eagle Ford samples from commercial sources were prescreened (to exclude samples with noticeable fractures) and tested for the Brazilian tensile strength at different orientation relative to the bedding plane, in addition to CT scan and X ray diffraction; Scanning Electron microscopy (SEM) is performed on a selected number of samples. Bulk XRD analysis is performed on pulverized rock subsamples and also on polished rock samples; large scaled lamination analysis is carried out on CT images; SEM images are used to evaluate whether fine scale fractures and mineral orientation has any effect on the tensile strength measured at different relative positions.
Our results show that the amount of ductile clay minerals is the most important factor; overall the brittle-quartz-and-calcite-rich Eagle Ford samples have higher average tensile strength (~700psi) whereas the ductile, clay-rich Mancos samples have a lower average tensile strength (~400psi). Within each group, the trend of the tensile strength and the relative amount of brittle minerals also exists. The sharply defined laminations of Eagle Ford shales results in a larger degree of anisotropy of tensile strength than these in Mancos Shale, and in the Eagle Ford samples there are more shear failures along the weak lamination planes. The failure along the laminations appears related to sedimentary features and not to mineralogy.
Pore pressure has proven to be one of the key drivers in the success of drilling and completing wells in the multi-stacked plays of the Delaware Basin petroleum system. Prediction of reservoir pressures and identification of abrupt changes in pressure regimes have become essential to the industry for economic success and for safety reasons. Pressure data coupled with petrophysical rock properties have yielded additional insights to the petroleum system across the Delaware Basin in southeastern New Mexico and Texas.
This paper describes the workflow used for generating a three-dimensional (3D) regional pore pressure model of the Delaware Basin for all geologic intervals. The 3D model was built using a database of over 23,700 mud weight recordings, Drill Stim Test (DST) ISIP readings and Diagnostic Fracture Injection Test (DFIT) pressures from over 4,000 vertical wells. Cross checked with petrophysical logs that deviated from normal compaction trends (NCT) help verify the extent and depths of pore pressure throughout the basin. This data was checked and then geostatistically distributed throughout an earth model. This process yielded three properties typically used by drilling engineers for well planning: Mud weight (ppg), pore pressure (psi), and pressure gradient (psi/ft) for any location in the 3D model. The 3D model was validated by cross-checking it against actual drilling reports and mud weights from horizontal wells.
Using this model, predictions for abnormally pressured zones can be extracted along the planned wellbore, thus helping to avoid drilling and completion challenges. The model also demonstrates a distinct lithologic change preceding a large pressure spike, indicating a regionally identifiable sealing stratigraphy. This may help to explain the differences in pressure regimes across the Delaware Basin.
This paper looks at using predictive modeling of the present-day pore pressure in the Delaware Basin as a key driver to understanding drilling risks, well performance, fluid volumes, and well stimulation techniques. Prediction and identification of pore pressure regimes has proven to be an essential component for the industry for safety, mud systems, fracture stimulation designs, and production success within multiple basins (Loughry et al., 2015). With the higher costs associated with drilling and completions, an operator may not want to perform a Diagnostic Fracture Injection Test (DFIT) or Drill Stem Test (DST) with every well due to the expense and time involved. DFIT's require isolation of zones, long shut-in times and a yield small radius of investigation (Friedrich and Monson, 2013). Accurate collection of DST's also requires additional time for testing in low permeability unconventional reservoirs.
There are, however, numerous mud weights recorded on mud logs throughout the basin, as well as hundreds of log suites containing acoustic curves to leverage and to fill in data gaps. This paper demonstrates a workflow to combine widely available data types with the smaller dataset of highly accurate measurements into a 3D earth model of pore pressure. This aids in the prediction of abrupt changes while drilling and completing wells.
Guar-borate crosslinked fluids have been successfully used in hydraulic fracturing operations for decades. These fluids are often preferred because of cost, ease of use, and robustness. Additionally, borate fluids are renowned for their ability to recover viscosity after exposure to high shear, a process commonly referred to as “rehealing.” With the prevalence and reputation of these fluids, it is easy to become complacent and rely on the assumption of rehealability when pushing borate fluids to their operational limits. This is particularly true in the current climate of cost minimization. However, there are situations in which borate fluids might not reheal, or the rehealing process is significantly retarded. Because common assumptions about borate fluids cannot be assured in all situations, understanding the variables that affect performance is imperative.
This paper explores the properties of instant and delayed borate crosslinked fluids under different shear rates, shear histories, and a range of pH values. Various experiments were conducted to investigate the viscosity and the ability of viscosity to recover under different shear histories, temperatures, and pH values. This paper focuses on optimizing the fluid chemistry to provide the desired viscosities from the surface to deep within the fracture.
The work completed demonstrates how several borate fluid formulations can generate nearly identical viscosity profiles under a single shear rate, but vastly different profiles after exposure to high shear. If shear history is not considered in fluid design, some formulations could appear feasible during initial testing but fail to provide the desired viscosity in the near-wellbore (NWB) region during field operations. Assuming borates will simply reheal without consideration of pH and shear history on rehealing time could give rise to premature screenouts.
Borate crosslinked fluids are viewed as simple and forgiving. This is true to a point, but there are limitations that can be overlooked if the appropriate testing is not performed and formulations are stretched to their limits. The information presented in this paper demonstrates where assumptions about borate fluids' ability to reheal fail, while providing recommendations that can help ensure the desired viscosity is maintained throughout the treatment.
Hussain, Maaruf (Baker Hughes Research Center, Dhahran Global Technology Center, King Fahd University of Petroleum and Minerals) | Minhas, Naeem (Baker Hughes Research Center, Dhahran Global Technology Center) | Agrawal, Gaurav (Baker Hughes Research Center, Dhahran Global Technology Center) | Cantrell, Dave (King Fahd University of Petroleum and Minerals)
A recent geology/mineralogy research group project focusing on carbonate source rock repeatedly observed unique pattern of microfractures. Observations indicated that diagenesis-led mineral distribution predisposes rock to a certain fracture pattern. If this was correct, then next question was whether dolomitization preceded fractures or vice versa. The research effort used advanced microscopy (optical and scanning electron microscopy-SEM) along with high-resolution mineral mapping on many samples to answer these questions. The project established a structural-diagenetic sequence of a dolomitic limestone source rock reservoir and fracturing. Impacts of dolomite influence on fracturing in limestone (mainly composed of calcite minerals) were studied using the quantitative evaluation of minerals obtained from a scanning electron microscope (QEMSCAN) mineral mapping technique. The relationship of other minerals to fracturing such as clay minerals within same rock was also analyzed.
In all observations, dolomitization preceded fractures. This was inferred from the absence of dolomite mineral precipitates within the fracture veins. Other observations noted fractures that cut through the host calcite minerals but were deflected away or around dolomite minerals. In a few instances the deflections created multiple fractures that continued the propagation. Fractures also cut through the clay minerals. This observation implied that the degree of dolomitization and dolomite distribution within the calcite matrix impacted fracture propagation in a carbonate source rock reservoir. A well-dispersed dolomite minerals structure in a limestone source rock reservoir contributed to rock toughness, resisted fracture propagation, and possibly generated multiple fractures, because the dolomite grains acted as stress concentrators. This scenario resulted in a larger surface area created by fractures than the stimulated reservoir volume. The energy required to propagate these fractures was high, compared to fractures that were not affected by dolomite and did not need to change direction. These fractures were expected to remain open to some degree, even after the load was removed, due to the teething created by the need for the fractures to deflect.
These observations have the potential for a better understanding of fracture architecture in relation to mineral distribution within a given rock. This information can provide additional input for consideration when determining fraccability index based on rock properties.
The conventional Arps hyperbolic decline model was developed to estimate ultimate recovery for conventional reservoirs which quickly enter the boundary dominated flow regime. Arps' model is usually optimistic when applied to low permeability reservoirs, depending on the empirical exponent (b-value) selected to match the long-duration transient flow in these reservoirs and on the time at which the analyst switches from the original b value to a lower value (often zero) to implement the modified Arps model. In addition, this standard procedure in complicated by the poorly understood effects of multi-phase flow in gas condensate reservoirs. Given the uncertainty in results from traditional models, new tools to supplement the ones in use today are required to improve the accuracy of our production forecasts.
In this paper, we used compositional reservoir simulation for retrograde condensate fluids to generate synthetic production histories. These production data, based on robust numerical simulation, were then used to evaluate forecasts using the initial history from simulation for matching and forecasting with each of several models used in the industry including Arps, Duong, and Stretched Exponential (Power Law) decline method. In addition to this we investigated the use of rate transient analysis (RTA) and principal component analysis (PCA), both of which use readily available field production data to history-match and forecast the future production data. RTA matching and forecasting algorithms are often based on the Ozkan's analytical trilinear flow model, which cannot be used to nonlinear multiphase flow case such as the gas condensate reservoirs without modifications. Unlike rate transient analysis, PCA is a non-parametric method which can be used to forecast and predict the production from gas condensate reservoirs. The simulated production histories were analyzed by this method to history match and forecast the production of simulated wells. In addition to this, the method was verified by using field data from the Eagle Ford Shale. We also investigated the similarities and differences between conventional and unconventional reservoirs and how multiphase flow is manifested in production diagnostic plots. For multiphase flow in gas condensate reservoirs, liquid dropout and relative permeability effects below the dew-point pressure have to be incorporated to accurately model the flow of both condensate and gas
As expected, we found that no approximate method reproduces the forecasts from compositional simulation. Nevertheless, we recognize that more rapid approximate methods will be required for routine analysis. Understanding the limitations of different approximate methods in given circumstances, as identified in this paper, should lead to optimal use of these methods.
Hydrocarbon-bearing ultra-tight formations generally exhibit heterogeneous, anisotropic, and pressure-dependent petrophysical properties. Consequently, various laboratory measurements on separate core plugs and crushed rock samples from tight formations tend to generate inconsistent petrophysical estimates. These inconsistencies are further escalated by the existence of varied pressure- and pore-size-dependent fluid flow mechanisms in the nanopores of ultra-tight formations. We circumvent such discrepancies in petrophysical estimates by simultaneously estimating six petrophysical parameters from laboratory-based pressure-step-decay measurement on a single ultra-tight rock sample. The proposed method involves nitrogen gas injection into an ultra-tight rock sample at multiple stepwise pressure increments, high-resolution pressure-decay measurement at the outlet, followed by a deterministic inversion of the measured downstream pressure data based on numerical finite-difference modeling of nitrogen gas flow in the ultra-tight rock sample.
This work is performed with an aim to improve the petrophysical estimates previously obtained from pressure-step-decay measurements using only a Klinkenberg-type gas slippage model. We implement a transitional transport model that can handle both slip and diffusion. The proposed method was applied to nine 2-cm-long, 2.5-cm-diameter core plugs extracted from a 1-ft3 ultra-tight pyrophyllite block. We estimated the intrinsic permeability, effective porosity, pore-volume compressibility, pore throat diameter, and two slippage-Knudsen diffusion weight factors parameters. Accuracy of the estimates depends on the physical models incorporated in the forward model and on the error minimization algorithm implemented in the inversion scheme. The estimation results are independent of initial guess of intrinsic permeability, effective porosity pore-volume compressibility, and pore throat diameter in the range of 3 nd to 300 nd, 0.01 to 0.15, 10-2 to 10-6 psi-1, and 60 nm to 500 nm, respectively. The average estimated values of intrinsic permeability, effective porosity, pore-volume compressibility, and pore throat diameter of the nine ultra-tight samples are 86 nd, 0.036, 2.6E-03 psi-1, and 195 nm, respectively. Notably, the two inverted slippage-Knudsen diffusion weight factors indicate that the gas transport mechanism in the nine ultra-tight pyrophyllite samples is completely dominated by slip flow without any Knudsen diffusion or transitional flow even though the Knudsen numbers across the samples during the entire duration of the pressure-step-decay measurements are in the range of 0.01 to 1.