Organic-rich shales are often found to be strongly anisotropic. Their dynamic and static elastic properties depend on their intrinsic anisotropy and the anisotropic in-situ stress field. We report pseudo-triaxial tests on Eagle Ford shales with axial load normal and parallel to beddings, respectively. From the experimental data, regardless of being from dynamic or static measurements, the elastic parameters present strong angular dependences: a much higher Young's modulus and a higher Poisson's ratio in the bedding-parallel direction. The deviatoric load orientation with respect to beddings leads to different nonlinearity and hysteresis in the stress-strain curves. From the microstructural point of view, the deviatoric load induces elastic compaction as well as some non-elastic processes such as frictional sliding and crushing of asperities at crack surfaces or grain boundaries. Hence, the statically derived parameters are sensitive to the anisotropic stress state and load-unload history. However, those microstructural alternations bring very small effects on the dynamic parameters. The dynamic Young's moduli are systematically higher than the static Young's moduli, whereas the dynamic Poisson's ratios are lower in the loading process and higher in the unloading process than the static Poisson's ratios. When the load is initially reversed, the static parameters approach the corresponding dynamic parameters, reflecting the rock bulk properties without any frictional sliding effects.
Shales comprise more than 70% of the drilled formations in most sedimentary basins and form the seal or source rocks of many hydrocarbon reservoirs (Vernik and Nur, 1992). As the unconventional oil and gas boom, the organic-rich shales have drawn global attention in the past fifteen years. These shales serve as both source rocks and reservoirs in resource shale plays. Because of the extremely low porosity and permeability, extracting economic hydrocarbon flows from such reservoirs requires the applications of horizontal drilling and hydraulic fracture stimulation techniques (Rickman et al., 2008). To this end, their geo-mechanical properties, such as Young's modulus and Poisson's ratio, require a better understanding in consideration of the importance in predicting the in-situ stress profile, evaluating brittleness, and optimizing horizontal well and hydraulic fracture designs (Higgins et al., 2008; Rickman et al., 2008).
Kumar, Abhash (National Energy Technology Laboratory / Leidos Research Support Team) | Hu, Hongru (University of Houston) | Bear, Alex (National Energy Technology Laboratory) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (National Energy Technology Laboratory / University of Pittsburgh)
Hydraulic fracturing involves the injection of large amount of fluid, typically water, in the reservoir rock that increases fluid pressure in the pore spaces and alters the stress condition of the rock significantly. This sudden change in the stress condition is strong enough to create new fractures in the rock or stimulates slip along the pre-existing fractures. Creating new fractures or inducing slip along multiple pre-existing fractures, both results into a marked increase in the interconnectivity of pore spaces and enhance the flow of oil and gas within the stimulated volume. The distribution of microseismic earthquakes that are generated during hydraulic fracturing is traditionally used as a proxy to estimate stimulated reservoir volume (SRV). For efficient extraction of oil and natural gas, it is extremely important to get an accurate estimate of the SRV. However, a simple energy balance calculation suggests that the combined energy released from all microseismic earthquakes during hydraulic fracturing is a small portion of the total input energy, supplied to the reservoir rock in the form of injected fluid. The difference in the total input and output energy suggests some alternate mechanism of deformation in the reservoir rock during hydraulic fracturing that need to be considered to get more accurate estimate of the total stimulated reservoir volume. Recent studies of hydraulic fracturing in the Barnett Shale, Marcellus Shale, Eagle Ford Shale and Montney Shale found the evidence of low-frequency events, with drastically different seismic signature (frequency, amplitude, time duration) than traditional microseismic earthquakes. These low frequency (1-80 Hz) earthquakes are proposed to be associated with either jerky opening or slow rate of slip along pre-existing fractures that are unfavorably oriented in the ambient stress field and releasing as much as 1000 times the energy of an average microseismic earthquake.
We identified multiple long period long duration (LPLD) earthquakes in the surface seismic data recorded during hydraulic fracturing of the two Middle Wolfcamp Shale wells in Reagan County (RC), TX. LPLD events identified in this study show a dominant P-wave signal that persists for 5-10 seconds and significantly long duration compared to traditional microseismic events. We also noticed finite decay in seismic amplitude across the surface-monitoring array suggesting a non-regional or local source of deformation for their origin. We aim to compare and contrast our surface seismic observations on LPLD with seismic data from two 24-tool borehole arrays that were deployed in vertical section of the two nearby treatment wells. This comparison between surface and borehole data will be of strategic importance to evaluate the efficiency of surface seismic monitoring and it would also be helpful in finding more LPLD events in borehole data that are usually less contaminated with the surface noise.
Siddiqui, Fahd (University of Houston) | Rezaei, Ali (University of Houston) | Dindoruk, Birol (University of Houston / Shell International Exploration and Production) | Soliman, Mohamed Y. (University of Houston)
Prior knowledge of reservoir fluid type and properties aids in selecting and optimizing completion and surface facilities. Fluid properties prediction has an impact on in-place volumes and reservoir performance management including optimized well placement. We present a data-driven fluid variation modeling approach using machine learning. The aim is to predict the fluid type and oil API gravity for a given location and depth and optimize the completion design for the Eagle Ford shale.
Data from 9400 Eagle Ford shale wells were compiled, cleaned, and analyzed. Data was then divided into training and test sets. The test set was set aside for validation to prevent any training bias. Data visualization and statistical analysis was carried out, which revealed patterns and features within the training data. Three separate artificial neural networks (ANNs) were then constructed on those features, and a supervised learning algorithm was employed to train on the training set.
The first ANN predicts the oil API gravity based on a given coordinate: latitude, longitude and depth information. This network uses Mean Squared Error (MSE) loss function with the Root Mean Squared (RMS) regression optimizer. ANN-1 reported an error of 2.4 API which is well within process dependency of the API measurements and within the potential experimental errors. The second ANN predicts the most likely fluid type along with the probability, which can be used as a measure of confidence. ANN-2 uses the categorical cross-entropy loss function with the Adam optimizer (Kingma (2014)). Finally, ANN-3 predicts the hydrocarbon production of the first 12 months based on the well location, lateral length, depth, number of stages, proppant volume and gel volume. All three models were then validated on the test set, and a good match was obtained. Based on the data-driven models, an optimization scheme was created to maximize cash flow from the first 12 months of production based on varying the lateral length, the number of stages, proppant volume, and gel volume used. The resulting optimum parameters are then represented visually on the map of Eagle Ford, along with oil and gas production, and cash flow.
Even though the presented method was trained for Eagle Ford, data from other formations can be incorporated and re-trained, including other proxies for every additional basin, to create a general neural network predictive model on all formations; or to create smaller networks that would make accurate predictions within the specified formation. This approach will lead to a continuously improving and learning process for each additional field and play.
It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture contact area. However, there is no efficient approach to estimate the fracture surface area at present. In this paper, we propose a method to calculate the fracture surface area based on the falloff data after each stage of the main hydraulic fracture treatment.
The created hydraulic fracture closes freely before its surfaces hit on the proppant pack, and this process can be recognized on the pressure falloff data and its diagnostic plots. The pressure decline rate during fracture closure is mainly caused by fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, we may assume the same leakoff coefficient among all stages, so the total fracture surface area can be calculated for all stages to meet the requirement of the fluid leakoff rate.
Wellbore storage effect, friction dissipation and tip extension dominate the early pressure falloff data. While the transient dominated by friction losses typically lasts about one minute, tip extension may end after about 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture closure trend. The fracture closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late time unit slope. The behavior of the late unit slope depends on the pressure decline rate, or correspondingly, to the fluid leakoff rate. Therefore, the total fracture surface area can be estimated using hydraulic fracture design input values for formation leakoff coefficient and fracture closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures, effectively all fracture surfaces contributing to the fluid leakoff.
We applied the approach to all stages in a horizontal well that exhibit the fracture closure behavior. The approach shows promise as a straightforward way to estimate fracture surface areas that could, enable, in turn, an early estimate for the expected well performance.
Dande, Suresh (University of Houston / Sigma Cubed Inc.) | Stewart, Robert R. (University of Houston) | Myers, Michael T. (University of Houston) | Hathon, Lori (University of Houston) | Dyaur, Nikolay (University of Houston)
In a hydraulically fractured reservoir, estimating propped reservoir volume is key to predict production. In this study, we use various samples, including 3D-printed models with air-filled plus sand and ceramic proppant-filled fractures, as well as Eagle Ford Shale samples with artificially created fractures with air and sand-proppant. From the 3D-printed model in uniaxial compression experiments, we found that Vs is decreased by 10% for the sand-proppant model, and the Young’s modulus of sand-propped models are lower than the air-filled or unpropped models, suggesting that propped models may be more compliant. Normal compliance calculated from the static data confirms that propped models are more compliant. We extend this experiment with Eagle Ford Shale samples, we find that S-wave velocity is faster in propped rock in all directions (00, 450, 900 to the bedding). We also observe that Vp normal to the bedding direction is faster in propped rock than in unpropped rock. The increase in shear velocity could be attributed to the addition of faster material(sand) to the saw cuts. Though we are looking at the same problem, the different results between 3D printed and Eagle Ford shale may be real as the materials are different and experiment procedures are different.
This work presents a laboratory investigation of miscible ethane foam for gas EOR conformance in low permeability, heterogeneous, harsh environments (<15md, 136,000ppm total dissolved solids with divalent ions, 165°F). The use of ethane as an alternative to CO2 presents several operational and availability strengths which may expand gas EOR applications to depleted or shallower wells. Coupling gas conformance also helps improve displacement efficiencies and maximize overall recovery. Minimum miscibility pressure displacement tests were performed for dead crude oil from the Wolfcamp Spraberry trend area using ethane and carbon dioxide. Aqueous stability, salinity scan, and static foam tests were performed to identify a formulation. Subsequent foam quality and coreflood displacement tests in heterogeneous carbonate outcrop cores were conducted to compare the recovery efficiencies of three processes: a) gravity–unstable, miscible ethane foam; b) gravity–stable, miscible ethane, and; c) gravity– unstable, miscible ethane processes. Slimtube tests comparing ethane to CO2 resulted in a lower MMP value for ethane. We identified a stable surfactant blend capable of Type I microemulsion and persistent foams in the presence of oil. Core floods conducted with gravity-unstable miscible ethane foam, gravity stable miscible ethane, and gravity-unstable miscible ethane recovered 98.4%, 61.9%, and 42.6% OOIP respectively. Our work shows that miscible ethane injection processes result in significant recoveries even under gravity-unstable conditions. The addition of foam further enhances overall recovery at laboratory scale, showing promise for field applications. Unconventional plays present a challenging set of operational conditions which include high temperature, high salinity, low permeability, and fracture networks. Aggressive development of plays and low primary recovery values reveal a potential for enhanced oil recovery methods. Our work demonstrates that miscible ethane foam has the advantage of better conformance control availability that can satisfy these requirements.
Enhanced oil recovery methods have been instrumental in recovering additional oil from reservoirs after primary recovery cycles. Gas injection EOR, in particular, has contributed to the profitable recovery of oil from deep fields with low permeabilities and light to medium oils (Taber et al., 1997). Gas injection processes employ the use of nitrogen, hydrocarbon, or carbon dioxide gases to increase incremental oil recovery; they can be classified as miscible where the important mechanisms of oil displacement are miscibility and interfacial tension (IFT) reduction or immiscible where viscosity reduction and oil swelling play notable roles (Lake et al., 2014). A recent worldwide biennial survey of EOR projects shows carbon dioxide (CO2) and steam EOR as dominant production processes (Moritis, 2010). Miscible CO2 processes in the United States recently eclipsed steam EOR processes at 308,564 b/d compared to steam EOR's 300,762 b/d (Oil & Gas Journal, 2012). Apart from general gas injection issues such as viscous fingering and stability, CO2 flooding has several specific operational drawbacks. Poor selection of metals in production tubing for wells producing from CO2 flooded fields can result in corrosion, delays, and increased capital expenditures due to the presence of carbonic acid in upstream and midstream operations (Kermani and Morshed, 2003). Additionally, the formation of carbonic acid near injectors can cause dissolution and subsequent precipitation of rock minerals and asphaltene precipitation (Marques and Pimentel, 2016). Commercially profitable CO2 EOR projects also require sufficient transport infrastructure as well as vast quantities of naturally available injectant gas (Martin and Taber, 1992).
CO2 exchange method is one of the extraction techniques that is under development for the production of methane from gas hydrate resources, and the mechanisms and kinetics of the CO2-CH4 exchange process still remain unclear. We model this process with molecular dynamics (MD) simulation to reveal the reaction mechanism, find the optimal operating condition and enhance the conversion rate. The simulations are carried out at three different temperatures to study the impact of temperature on the exchange rate and the kinetics. The production runs are carried out at microsecond level in the NPT ensemble with pressure held at 5 MPa. The simulation results and the associated analysis show that at the investigated conditions, the CO2-CH4 exchange process involves a direct swap of the guest molecules without complete breakage of the water cages. Also, temperature has a significant impact on the kinetics of the process that the increase of temperature from 250K to 270K accelerates the procedure by at least 1.5 times. The reactions mainly occur at the hydrate surface, so that it is critical to enhance the penetration of CO2 into hydrate structures for large scale application of the CO2-CH4 exchange method.
Engineers commonly expect symmetric fracture wings in multiple transverse fracture horizontal wells (MTFHWs). Microseismic surveys have shown asymmetric hydraulic fracture grow away from the recent fractured wells and grow towards previous produced wells. It might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events and develops a simple model to simulate the fracture propagation and its impact on the well productivity. Motivated by the microseismic observations, we developed a simple fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Also, we developed a model to estimate the productivity of a well with asymmetric fractures. The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is located where stress field is different between its two sides.
Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.
Steam-Assisted Gravity Drainage (SAGD) is one of the popular methods for heavy oil production. The process is efficient and economical. However, it requires the use of large quantity of water and disposal of waste water can be costly. In addition, burning of natural gas for steam generation contributes to additional carbon dioxide generation, a known greenhouse gas, which is also undesirable. A method to heat up the in-situ oil without the use of injected water is highly desirable. Radio frequency (RF) heating of heavy oil reservoir is a potential method for oil recovery without steam injection. The evaluation of the potential of such method requires the coupling of a reservoir simulator with an electromagnetic (EM) simulator.
This paper describes the development and implementation of a flexible interface in a reservoir simulator that allows the runtime loading of third party software libraries with additional physics. Data is exchanged between the reservoir simulator and externally loaded software libraries through memory, therefore there is minimal communication overhead. The implementation allows for iterative coupling, explicit coupling and periodic coupling. This paper describes the mathematical coupling of the mass and energy conservation equations in the reservoir simulator with the Maxwell equations in an external library. The electromagnetic properties in the reservoir are highly dependent on temperature and water saturation, this dependence is accounted for in the coupled code using table look-up properties.
Canadian heavy oil and reservoir properties were used in our simulation investigation. We found that RF heating alone can be effective in heating up the in-situ water and reducing heavy oil viscosity by several orders of magnitude. As the in-situ water near wellbore was vaporized by RF heating, electrical conductivities were reduced to zero and thus allowed the EM wave to propagate further into the formation and heat up the water further away from the wellbore. With properly designed RF heating field pilots and tuning of EM and reservoir parameters, the coupled reservoir/EM simulator can be a powerful tool for the evaluation and optimization of RF heating operations.
The interface is sufficiently flexible to allow different types of multi-physics coupling. In addition to RF heating, it has also been used for reaction kinetics and geomechanics coupling with a reservoir simulator. It has been used for large scale coupled full field simulation with over 30 million cells.