Search

Hydraulic fracturing induces the shear failure of natural fracture which contributes to complex fracture network. The magnitude of fracture slip potentially causes some undesirable consequences including wellbore instability, casing deformation and fault reactivation. Therefore, it is important to predict the fracture slip induced by hydraulic fracturing for a safe and efficient stimulation. In this paper, we used a 2D hydro-mechanical coupled model to predict the injection-induced slip. The hydraulic and natural fractures are embedded in formations with cohesive zone model. The fracture propagation, rock deformation and wellbore slip displacement are captured in the 2D model. The wellbore slip displacement is input into a small-scale 3D mechanical model of casing in slip rock to simulate casing behavior. Casing curvature is also introduced to assess casing integrity. Results indicate that the rock deforms asymmetrically with respect to the wellbore after the shear failure of natural fracture. Particularly, there is a shear slip along the natural fracture. The simulation result shows that the casing failure mechanism is shear deformation induced by the fracture slip during hydraulic fracturing. The curvature of deformed casing is larger than that of directional well trajectory. The predicted results are validated by the logging and operation data from the field. This work provides a novel quantitative method for predicting fracture slip and evaluating well integrity during hydraulic fracturing.

Synergistic development of energy by combining geothermal and hydrocarbon gains an increasing attention. In practice, hydrocarbon reservoir fluids produced from oil and gas wells are used for electricity generation through a binary cycle power plant. To enhance the thermal recovery efficiency, we present an innovative design of in-situ geothermal power generation and illustrate a promising method of geothermal energy utilization in a cost-effective and environmentally friendly manner. This proposed design is an integration of thermoelectric generation technology, well completion and production operation. In this design, electricity is generated downhole by thermoelectric generators (TEG) installed on the outer side of the production string to convert the thermal energy to electric power. Heat transfer model is set up to determine the temperature field with a case study to demonstrate the downhole power generation efficiency. The results are compared with both simulation and experiment results. The proposed design capitalizes on existing hydrocarbon production wells and retrofit them for power generation. This practice can be a great complementary for surface power plants, and could reduce operational cost and extend the economic lifetime of oil and gas wells, especially for high water-cut wells in mature fields.

Hydraulic fracturing enables the commercial development of unconventional resources in shales and tight formations. The conductivity and complexity of created fractures are critically dependent on the rheology of fracking fluid and the mechanics properties of rocks. Literatures show that both the rheology of fracturing fluid and fracture propagation dynamics are affected by the temperature of fracturing fluid. Neglecting the temperature transient behaviour may defeat the purpose of fracturing optimization during fracture initiation, propagation, and sand packing. The objective of this paper is to investigate the impact of temperature on fracturing design by studying the transient temperature behaviour across a complex wellbore using numerical modelling by coupling a finite difference heat transfer model with a dynamic fracture propagation model. The study results show that with the injection of cold fracturing fluid, hydraulic fracture propagation is decelerated, and production prediction is thus lessened compared with the case ignoring temperature effect. For multistage fractured wells, fracture geometry enlarges along the fluid flow direction in a horizontal segment. This potentially lowers the cost of hydraulic fracturing designs.

The wellbore integrity plays an important role in petroleum operations like drilling, well completion and production. Caliper, Electrical image logs, Acoustic televiewers (ATV) and Optical televiewers (OTV) are some of the devices currently used in the industries to identify breakouts. However, these techniques are restricted in applications. For instance, caliper sometimes indicates the effect of drill spiral grooves as borehole enlargement zones; poor resolution and complicated processing procedure limit the application of the electrical image logs. The ATV and OTV which give better outputs are not often used due to the high cost of installation and operation. These limitations necessitated a new approach to quantifying the wellbore instability. This research work focuses on data analytics and the development of the Bayesian Algorithm (with code in Python) to predict the wellbore failure probability using real-time pore pressure and fracture gradients data obtained from the wellbore using modified d-exponent.

Summary The single-well chemical-tracer test (SWCTT) has been applied for decades with much success in estimating residual oil saturation in near-wellbore locations. The information obtained from an SWCTT is critical for designing a method for enhanced oil recovery (EOR). However, a key assumption in the conventional SWCTT is that only single-phase (water) is mobile. In reality, this is often not the case, and significant error can occur if the conventional SWCTT analysis method is used when multiple phases flow at the same time. The objective of this study is to improve the accuracy and precision of SWCTT interpretation in a multiphase-flow condition. In this paper, we propose an innovative procedure of SWCTT and modify the method of moment (MOM), aiming at the two-mobile-phase condition. In the development of the algorithm, a ratio parameter is introduced to adjust the calculated swept-volume difference between the conservative tracer and the partitioning tracer. In addition, a mixture injection of oil and water is required, instead of the pure-water injection in an SWCTT. The proposed approach is verified through numerical simulation on synthetic cases with known input parameters. The model being simulated consists of a radial-flow regime with a single vertical well in the center. The input oil saturation varies from 0.1 (immobile oil saturation) to 0.9. Our results show that the saturation estimated from the modified MOM matched the simulation input data, indicating that our approach is able to capture the saturations under two-mobile-phase condition. Moreover, the modified MOM can also be applied in single-mobile-phase condition and can improve the accuracy of conventional MOM.

Casing failure during hydraulic fracturing is infrequent, but its consequence and impact can be significant for the shale gas wells. It may result in inaccessible cased hole and environmental and safety concerns over wellbore integrity during the shale gas reservoir development. Based on theoretical analysis, numerical simulation and field measurement, the failure mechanisms of casings in shale gas wells are revealed. Through parametric sensitivity analysis, the countermeasures are recommended. Results indicate that one of the casing failure mechanisms in shale gas wells is shear deformation induced by the slip of shear fractures. The simulated casing deformation is consistent with the lead impression. Casing curvature is introduced to assess the traveling capability and casing integrity. The maximum curvature is significantly larger than that of normal directional borehole, which causes the resistance of downhole tools passing through casing. Decreasing the crossing angle and employing the cement with a low Young's modulus or even no cementing can be the effective measures to prevent casing failure in this mode. The research findings provide new evaluation criterion and controlling methods for casing integrity in shale gas wells under hydraulic fracturing.

The density distribution of hydrocarbon molecules in Nano-pore media affects the storage of gas, particular for shale reservoir which contains rich organic matters. The density distribution can reveal the adsorption effect which is related to the gas storage mechanism. In literature, researchers proposed using local density theory such as Lennard Jones Potential in lieu of molecular dynamics (MD) simulation and laboratory measurement because of its high computation performance. Core sample study shows that many pores in organic matter have cylindrical shape, but the curvature effect on gas storage has not been studied. Therefore, the thorough validation of this approximation needs to be done for different pore geometries, particularly for a multiple components system. In this study, we propose to study the shale gas storage under the reservoir conditions by a thorough comparison between the Lennard Jones Potential with Peng-Robinson EoS (LJ-PREOS) and equilibrium molecular dynamics simulation for cylindrical pores. We first compare the LJ-PREOS for a single component, and then extend the study to a binary system. The purpose of this comparison to quantify the boundaries under which the LJ-PREOS can be used as a proxy to study the gas storage and adsorption effect in shale formation. After Comparing the results from equilibrium MD simulation with new SLD-PR model, for the single component system, the density on the both sides (close to the pore wall) is much higher than the density on the center, which means the cylindrical wall has a significant adsorption effect on methane molecule. For the binary component system, the mixture density distribution is similar to the single component system, which is higher density closer to the wall and lower density on the center. Furthermore, from the MD simulation results, for the density distribution of each single component in binary system, it is clearly show that both components are still under adsorption effect from the wall, but the butane molecule largely concentrate close to the edge of pore, which means the cylindrical wall has larger impact on butane molecule than methane molecule. With the validated model, we developed a framework to estimate the gas storage capacity of the organic matters in shale formation with different pore size distributions (PSD). Neglecting PSD may lead to 30% under estimation of gas storage in shale gas formation. To our knowledge, this is first validation of cylindrical pore adsorption for a multiple components system using MD modeling even though many researchers have used this hypothesis in their studies. We also proposed a new framework of estimating gas storage capacity in shale formation without distinguishing the adsorption and free gases in the organic pores with the effect of pore size distribution.

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organic-rich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity.

Shale gas development in the Sichuan-Chongqing region in China has experienced a high level of casing deformation or failure during hydraulic fracturing treatment, which has resulted in significant productivity decline and economic losses. This problem has motivated many studies in the literature but focusing on the shearing deformation using the finite element method. This paper categorizes the casing failure modes and mechanisms in the region and presents casing collapse laboratory results. The designed laboratory tests rendered us critical data points in casing deformation under different loading scenarios. For multiple stage hydraulic wells in the region, we propose to use a strain-based protocol for casing design instead of the current design based on maximum stress.

The well performance in Coal-Bed Methane (CBM) reservoir is highly dependent on the conductivity of hydraulic fracture created to increase well production rate and contact area with the reservoir. Aimed at improving the effective fracture length of hydraulic fracture in CBM reservoir and the seam proppant concentration, the objective of this paper is to investigate the migration of variable density proppant particles in hydraulic fracture and seams using numerical modeling and simulation. In the proposed model, the interaction among fracture proppant particles distributed in a pseudo fluid model is taken into consideration. Comparison between the model calculation and field radioactive tracing logging interpretation shows that the proposed model is accurate and reliable in applications. Additionally, we carried out the sensitivity study on the viscosity of fracking fluid, fracture area, proppant density, injection rate and other factors. It is shown that, with the condition of a confining pressure of 69 MPa and an ambient temperature of 90 °C, the crush value of nutshell proppant is less than 2%, which meets the field application requirements. Furthermore, with the increase of both fracturing fluid viscosity and injection rate, the propped effective fracture length increases, and lead to a more uniform distribution of proppants. The increase in proppant particle diameter, inversely, results in a decrease in the effective fracture length. As for variable-density proppant, the effective crack support length would be longer than the single ceramic proppant, and the particle distribution of the case with variable density is more uniform.

Summary On the basis of the wellbore and reservoir heat-transfer process during deepwater drilling, a heat-transfer model between wellbore and formation is built up for two different conditions: without riser and with riser. Wellbore and formation temperature distributions under different drilling-fluid-injection temperatures, flow rates, circulating times, and drilling depths are simulated by use of this model. Taking the hydrate-phase equilibrium into consideration, a possible region of hydrate-formation dissociation is analyzed, and effective methods are proposed to control the hydrate dissociation. The results indicate that, during shallow formation drilling, the increase of drilling-fluid flow rate will cause the wellbore temperature to rise, but below the hydrate-dissociation temperature in the whole process; during deep-formation drilling, drilling fluid is heated, and the heat is transferred from the deeper formation to the shallower formation through fluid circulation. Thus, the hydrate-reservoir temperature increases gradually along the wellbore radial direction. Hydrates will dissociate after the hydrate equilibrium temperature is reached; this may cause wellbore collapse or methane leak from the reservoir and result in disaster. To control hydrate dissociation during deepwater drilling, attention should be paid to the period of deep-formation drilling. Sensitivity studies indicate that the risk of hydrate dissociation rises as the drilling-fluid-injection temperature, flow rate, and circulating time increase.

Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention. To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount. The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system. The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.

Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods. The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology. This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units. This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.

Characterized by rock sediments and complicated storage mechanisms, shale reservoir development is to create flow systems comprised of complex natural fissures and hydraulic fracture stimulation such that the hydrocarbons in the reservoir can be recovered economically. The prediction of shale reservoir production performance is critical for reservoir management and challenging due to the compounding nature of multiple flow mechanisms one encounters during the life of a shale gas well. Given empirical nature, many models based on curve-fitting historical production data prone to inaccurately forecast well's rates in shale gas reservoirs, particularly when the production history of a well is short. This paper further extends the applicability of the Connected Reservoir Storage Model (CRSM) to shale reservoirs. The CRSM was derived from diffusivity theory by using historical production rate and bottomhole flowing pressure (BHFP) to determine the reservoir behavior and unit pressure response, and it can be conveniently used to predict production performance under variable operating conditions. The CRSM is mathematically robust and easy for application since it can be determined with limited reservoir information without knowing the reservoir geometry or reservoir permeability. This study uses the operational history of a shale gas well to demonstrate the CRSM's capability in rate prediction and couples the model with stochastic methods to approximate the most probable outcome under variable operating conditions.

Summary Hydraulic fracturing has been applied as an effective method to increase gas production from shale formations; however, this method has also raised concerns about its adverse impacts on environment. For example, in the Marcellus shale formation, some measured radon-gas concentrations exceeded the safe standard. Therefore, it is important to quantitatively evaluate radon concentration from fractured wells. However, existing researches have not successfully conducted a systematic and predictive study on the relationship between shale gas production and radon concentration at the wellhead of a hydraulically fractured well. To address this issue and quantitatively determine the radon concentration, we present the mechanisms of radon-gas generation and releasing, and conducted numerical simulations on its transport process in the subsurface formation system. The concentration of radon in produced gas is related with the original sources where the natural gas is extracted. Radon, generated from the radium alpha decay process, is trapped in pore spaces before the reservoir development. With the fluid flowing through the subsurface network, released radon will move to surface with the produced streams such as natural gas and flowback water. Our study shows that the radon concentration at wellhead could be significant. Influential factors such as natural-fracture-network properties, formation petrophysical parameters, and fracture dimension are investigated with sensitivity studies through numerical simulations. Analysis results suggest that radon wellhead concentration is strongly related with production rate. Thus, careful production design and protection are necessary to reduce radon hazard regarding the public and environmental impact.

Hydraulic fracture geometry is of the interest in optimizing stimulation treatment and forecasting production potential. Current diagnostic tools such as tiltmeter and microseismic are insufficient in evaluating fracture geometry. Knowing that gas from the shale reservoir has a much higher mobility than fracking fluid, partitioning chemical tracer is employed so that tracer data can be obtained earlier and more complete. The proposed approach is examined by synthetic numerical simulations. On the semi-log plot, tracer production declined tail clearly divides into two straight-line segments. Applying the moment of methods to the entire tracer production data gives the total volume of hydraulic fracture and the invaded matrix swept by the tracer due to leak-off. Additionally, extrapolating the first segment of tracer decline tail using the exponential law yields a volume that is close to the actual hydraulic fracture volume, especially when fracture permeability is several orders larger than matrix permeability.

Horizontal drilling and hydraulic fracturing enabled the extraction of hydrocarbon from tight formations in countries such as the United States, China, and Argentina. Some factors such as stress anisotropy, formation temperature and quantity of natural fractures are reservoir specific and should be considered in the completion design; otherwise, high rates and pressures applied during hydraulic fracturing in a long horizontal section could induce wellbore integrity issues. Based on field parameters, we studied how the integrity of the cement and casing is affected during these operations using finite element analysis (FEA) to study the stress concentration in casing and cement. The yield criterion of equivalent von Mises stress was applied in order to verify if the stresses were exceeding the casing yield strength and the cement compressive strength. Simulation results revealed that a poor centralization that contributes to the formation of drilling fluid voids in the cement will induce casing failure during hydraulic fracturing operations. The equivalent maximum stress can increase from three to four times in casing and cement from a concentric case to an eccentric case in a cement sheath with voids.

The characterization of hydraulic fractures is critical in well performance evaluation and production forecast. In practice, many inverse methods such as tracer analysis, micro-seismic and acoustic sensors are applied to quantify the geometry of the created fractures. Unlike the above methods that involve additional measurements, this study focuses on the water production by studying their flowback volumes, chemistry and their relationships with fracture characteristics. In this study, the flowback water data are used to analyze hydraulic fractures' characteristics. According to the flowback water analysis for hydraulically fractured wells in Marcellus based upon ion mass transport, it is easy to notice that, in most cases, fracture network with smaller apertures generates lower water recovery and higher flowback ions concentration simultaneously, and vice versa. By study the flowback water, the average width of fractures can be roughly estimated.

Summary Because of its efficiency, cleanliness, and reliability, natural gas is an important sector in global energy consumption. It supplies nearly one-fourth of all energy used in the United States and is expected to increase 50% within the next 20 years. More gas-delivery infrastructure is being constructed to meet the transportation requirement of the ever-increasing demand for natural gas, while at the same time, the existing gas infrastructure is aging. Ensuring natural-gas-infrastructure reliability is one of the critical needs for the energy sector. Operators prefer to capitalize on the transportation capacity of these old pipeline systems to reduce the cost for building new pipelines, but they run a high risk of encountering partial blockage in the pipeline, which can cause operating pressure to exceed the safety specification. Therefore, the reliable and timely detection of a partial blockage in a gas pipeline is critical to ensuring the reliability of the natural-gas infrastructure. To design proper pigging tools, it is important to detect the location and size of partial blockages. Physical inspection and mathematical-model simulation are used to identify partial blockage in gas pipelines. Generally, the physical method can result in an accurate detection of the location and size of the partial blockage, but at the expense of production shutdown and high cost/long time to run the physical detection, which is a very expensive measure in a long-distance gas pipeline. The mathematical simulation detects partial blockage through numerical modeling, which could provide a quick evaluation at a much lower cost, but with higher uncertainties. Our literature review indicates that a simple, practical, and reliable method to detect partial blockage without a recorded inlet or outlet pressure is in great demand. In this study, we develop a multirate test method to detect partial blockage in a gas pipeline. By conducting multirate tests, the location and size of the partial blockage can be evaluated. The new method can be applied under the conditions of no measured inlet or outlet pressure, which have not been investigated before. It is worth locating a partial blockage under these conditions because as oil and gas exploration and production move to harsh environments, no pressure gauge being installed at the inlet or outlet of the pipeline can be a common circumstance in the fields. Even for onshore fields or fields with easy access, pressure is not transferred to the central office in real time. In addition, the metering equipment and pressure gauges installed in the pipeline may not be working. Therefore, our method provides a practical, quick, and low-computational-cost approach to estimate partial blockages corresponding to these conditions. The partial blockages in a single pipeline and in parallel/looped pipelines were evaluated in this project by use of the proposed method. Considering that most of the complicated pipeline systems under operation can be decomposed into basic units, such as single pipeline and parallel/looped pipelines, the proposed model can realistically and feasibly identify partial blockage in a complex pipeline network. Furthermore, existing studies assume only single partial blockage in the pipeline, which limits the application of available models because the detection will be misleading if there is more than one partial blockage in the pipeline. To fill this gap, we developed a model to differentiate the single-partial-blockage scenario from the multiple-partial-blockage scenario on the basis of multirate tests. The identification is critical because it guides partial-blockage detection in the right direction.

Summary Permanent-downhole-gauge (DHG) technology has been used widely in deepwater-reservoir development in the last decade and is playing an increasingly significant role in real-time reservoir/well surveillance and management. Tidal signals extracted from this highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock/pore compressibility. Most previous works have treated tidal signals as pressure "noise," and little has been discussed on how to use tidal information in reservoir characterization. This paper will address how to use the fast Fourier transform (FFT) to extract tidal signals and the theories and methods for processing the signal to achieve reservoir characterization. In addition, a couple of examples from a deepwater field will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid-saturation change, and detect the presence of a secondary gas cap. This paper will show that FFT is a fast and reliable method for processing the DHG pressure data for tidal signals that can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signals are unique because they cannot be obtained in the laboratory, by simulation, or by direct measurement because of the scale affected by tides.

Chemical tracer is an alternative technique for hydraulic fracture diagnosis other than tiltmeter and microseismic mapping. Fracture volume is an essential parameter for stimulation optimization and production forecast. In our previous work, we proposed a simple, cost-effective method to assess the fracture volume using partitioning chemical tracer. In the hydraulic fracturing stage, a partitioning chemical tracer slug is injected along with the fracking fluid. In the created hydraulic fracture, the tracer partitions in both vapor and liquid phases and flow back in the production stage. By analyzing the tracer production data, we could estimate fracture volume and leak-off volume. This work will first investigate chemical tracer selection criteria for the purpose of fracture volume diagnosis. Tracer partition coefficient and tracer adsorption are the main considerations. Our results suggest a careful section is needed for partition coefficient, balancing the estimation accuracy and investigation area. In addition, the selected tracer should have negligible adsorption. Numerical simulation is another way to interpret tracer test. In the second part of this paper, we propose a modified Random Walk Particle Tracking (RWPT) algorithm to simulate the partitioning chemical tracer transport with multiple mobile phases. Output obtained through the RWPT is identical with analytical solution and its tracer critical breakthrough time is more accurate than the result from the finite-difference based simulations.

Carbonate reservoir with low permeability is developed using fracturing technology to effectively stimulate the reservoir for a higher productivity. However, as the carbonate reservoir features extreme heterogeneity, not every fracture is created equally as is obtainable through acidizing fracturing or using proppant. The objective of this study is to help make the decision among acid fracturing or proppant fracturing, to achieve an economically and operationally feasible treatment through extensive research of field cases on critical factors and numerical simulation. An ideal fracturing method of a carbonate reservoir should yield a high conductive fracture with a potential for long production duration under depletion scenario within an economic limit. We first review real field cases to identify critical parameters affecting fracture geometry and productivity; then we validate and quantify their individual effectiveness using 3D synthetic models with numerical simulation. In the simulation work, both treatments are evaluated by simulating the production of the reservoir for 1,500 days post treatment. Results are compared for different reservoir parameter variations including porosity, permeability, temperature, depth and young's modulus. Simulation of the field is continued for 1,500 days after the treatment to see the effect of the production enhancement for both types of treatment. This is also done to include long term loss of fracture conductivity and its effect on the overall production. Fracture geometry from each case is also analyzed and compared to the base case scenario. Even though hydraulic fracturing and acidizing technologies have been the dominant stimulation methods in unconventional resources and many variants have been developed, there is still no well-defined guideline which can help an operator to select the stimulation techniques suitable for their particular fields. This paper focuses on factors influencing decision making on the stimulation of carbonate reservoirs based on reservoir characterization. The advantages and limitations of proppant fracturing and acid fracturing are compared based on field applications, which can enable an operator to make quick and informed decision on which stimulation should be used. Numerical effort confirmed and quantified our observations. Comparisons have been drawn on different types of proppant and acid treatments and their effectiveness on the target reservoir. The study eventually comes up with identifying main factors of reservoir for treatment selection and recommendations are presented from these findings that which type of reservoir is best suited for which type of treatment. The novelty of the study is summary of previous field cases with a clear guideline on making decision in carbonate reservoir stimulation. As a further extension to this study, PVT data can also be included to see the extent of reservoir fluid change effect on the outcome of the treatment.

Petroleum exploration and production from Bakken and Three Forks formations in Williston Basin have achieved great momentum since 2005. To overcome the resistance of the low to extremely low permeability to hydrocarbons flow from reservoir to bottomhole, horizontal wells with multistage fracturing completion are applied to gain economical rate. Currently, horizontal lateral lengths that exceed 10,000 feet with more than 50 stages are not uncommon in Williston Basin. Field experience and practice indicate that different stage intervals usually results in different estimated ultimate recovery (EUR). Therefore, it is worth to identify optimal stage interval to stimulate horizontal lateral to cut costs through using the appropriate volumes of fracing fluid and proppant and to maximize profit by improving EUR. It should be noted that production from horizontal well with multistage fracturing is not only impacted by several factors such as geological characteristics, lateral length, orientation of horizontal lateral, fracing fluid, proppant, stimulation operating and procedure, and fracturing stage interval, but also by their interactions. To make the analysis reasonable, normalization analysis is exploited to differentiate the influences of different parameters. Sensitivity analysis of individual variable is applied to evaluate its influence on production. The analyses give a range of optimal stage interval for Bakken and Three Forks formations in different fields in Williston Basin. Considering the fact that variations in geology lead to different optimal stage intervals, it is appropriate to use a range instead of a single number as a reference in the well design. Although the results are derived from Bakken and Three Forks formations, the findings in this study can be employed in reservoirs with similar geological characteristics and reservoir properties. This study also identifies optimal ranges for operational parameters such as treatment pressure gradient, pumping rate, sand-to-water ratio, fracing fluid volume/length, and proppant mass/length, which are crucial to the cost reduction and operation efficiency.

Enhanced oil recovery techniques are having a growing interest for unconventional reservoirs to attack the low primary recovery factor issue, especially in a low oil price environment. Tight oil behaves a quick decline without much pressure support and thus jeopardies project profitability given a large initial capital requirement for horizontal drilling and massive multi-stage hydraulic fracturing operations. However, over 90% oil is still left behind in stimulated reservoir volume. It is imperative to understand the differences in production drivers in unconventional reservoirs, especially using EOR techniques, for example, how capillarity and adsorption may greatly alter phase behavior in nano-size pores. Previous studies showed that phase behavior and production mechanisms might be significantly different under nano-scale pore confinement in organic matter in Eagle Ford formation. This research was to shed light to quantify such differences under the influce of large capillary forces in organic and inorganic pores integrating petrographic and/or petrophysical measurements, for example, mercury injection capillary pressure (MICP) experiments. Further, this study developed a new methodology to consistently evaluate the effect of adsorption at the same pore size distribution as capillary evolved. Results showed that a large difference of phase and adsorption behavior existed for unconventional reservoirs in the oil window in the Eagle Ford formation, and pore size distribution played an important role in quantifying such differences. This may lead to additional rock-typing techniques to better characterize the Eagle Ford oil play and improve well expected ultimate recovery (EUR) and economics.

When a shale gas reservoir is being developed, two fundamental questions need to be answered: (1) how much gas is in place and (2) how much gas can be produced when reservoir is depleted to a specific pressure. This paper examines the pore size distribution impact on gas volume in place during reservoir depletion. A calculation procedure for a multiple component system will be presented with an illustration using Barnett core mercury injection data. Literature suggests that a monolayer adsorption model is not sufficient for shale gas reservoirs with multiple components in volumetric calculations. In this paper, we propose to use the cylindrical Simplified Local Density model with Peng-Robinson Equation of State (SLD-PR EOS) to solve the local hydrocarbon density distribution for gas in micro-and meso-pores. The integration of the local density over the pore width yields an average density. Pore size distribution (PSD) data such as mercury injection provide the pore volume contribution of different pore radii. Coupling the pore volume distribution with the calculated average density, we calculate the gas in place due to pressurization and adsorption under different pressures. The recovery from the shale reservoir is determined by repeating the process at different pressures. Because of the high non-linearity of the SLD-PR EOS, a trust-region optimization algorithm has been used to solve the local density profile. Pore size distribution has a tremendous impact on the gas storage capacity of a shale formation. Results from this study reveal that neglecting PSD can yield more than 40% errors for original gas in place (OGIP) calculation. Incremental pore volume is modeled with a Log-Gamma distribution for the Barnett field. OGIP sensitivities to the distribution parameters are also investigated. For the same porosity under the same ambient pressure and temperature, more small pores indicate more gas in place. Therfore under the same depletion process, more recovery can be expected from small pores. This paper utilizes MICP data for a Barnett gas shale core sample to demonstrate the calculation procedure for implementing core data, fluid characterization, and SLD -PR EOS modeling to calculate original gas in place. This paper has the following two novel points: (1) An improved OGIP calculation procedure for multicomponent gas shales is proposed using the cylindrical form of the SLD-PR EOS model and MICP data from core samples; (2) PSD has a tremendous influence on OGIP values in shale formations because of the presence of micropores and neglecting PSD can yield significant errors in OGIP values.

Effective fracture properties that contribute to the flow in the tight formations are very important in stimulation job evaluation, productivity estimation, and production forecast. However, there are no direct measurements on the volume of stimulated region or the effective permeability of fracture because hydraulic fractures not only stimulate local matrix, but also connect natural fractures. Therefore, the effective drainage volume contributing to production can be much bigger than the extension of hydraulic fractures. After a high initial rate, production data for stimulated tight formation has an extended transient flow period in which the matrix functions as a source and behaves in a transient fashion. This behavior can be captured by a dual-porosity model with transient matrix performance under a constant bottom-hole pressure. This paper studies the problem from an inverse perspective and couples the production data with an interporosity flow model to estimate the effective drainage volume that a well controls as well as the effective permeability that can be used for production rate forecast. The problem is solved in Laplace domain. The proposed model is validated with the numerical simulation and the field production data from Mississippian Lime. Furthermore, the interporosity model is sufficient to forecast the production trend from the given examples.

Abstract Permanent Downhole Gauge (DHG) technology has been widely used in deep water reservoir development in the last decade and is playing an increasingly significant role in real time reservoir/well surveillance and reservoir management. Tidal signal extracted from the highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock pore compressibility. Most previous works treated tidal signal as pressure "noise" and little has been discussed on how to utilize the tidal information in reservoir characterization. This paper will address how to use Fast Fourier Transform (FFT) to extract the tidal signal and the theory and method to process the signal for reservoir characterization purposes. In addition, several examples from some deep water fields will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid saturation change, and detect the presence of secondary gas cap. This paper will show that FFT is a fast and reliable method to process the DHG pressure data for tidal signal which can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signal are very unique because they cannot obtained in laboratory, simulation, or direct measurements because of the scale impacted by tides.

Abstract Nitrogen injection into gas condensate or volatile oil fields has been practiced as a method of pressure maintenance as well as enhanced hydrocarbon recovery in Rocky Mountains for more than two decades. Reservoir management has experienced miscible displacement in the gas cap, reservoir pressure maintenance, and reservoir blow down in different fields. In the implementation of nitrogen injection, a tremendous amount of experiences on injection and reservoir performance had been accumulated without appropriate documentation. Furthermore, even though nitrogen injection has been widely used in the world to enhance recovery by miscible displacement or maintaining reservoir pressure, literature survey shows that the experience with nitrogen injection is sporadic. This paper reviews reservoir characteristics and summarizes the lessons learned from nitrogen injection all of the world; then focuses on Rocky Mountains reservoir management to further analyze its production and surveillance, reservoir development stages in the life of fields, and the relationship between the fields and processing facility. Compositional reservoir simulation was performed to study the enhanced hydrocarbon recovery by injecting nitrogen and use nitrogen breakthrough information across the field as a continuous tracer to study the well connectivity between the injector and producer pairs. The main contributions of the paper are that it highlights the accumulated experience associated with nitrogen injection, and provides information on amenable reservoir features which can be used to select nitrogen as a viable alternative for enhanced oil recovery purpose. Introduction Nitrogen injection to hydrocarbon fields to maintain pressure and enhance hydrocarbon recovery has been used widely in different formation and fluid types, and significant amount of experiences with reservoir surveillance, nitrogen separation and hydrocarbon processing, and fluid phase behavior have been accumulated and documented (Sinanan and Budri 2012; Sanchez et al. 2005). In Rocky Mountains, the fields are of particular interest because of the fluid type and formation characteristics. Nitrogen injection into gas condensate or volatile oil fields in Rockies has been practiced for more than three decades. A number of fields (Figure 1) such as Painter Reservoir Units (PRU), and Ryckman Creek in overthrust, Anschutz Ranch East (ARE), and Glasscock Hollow, used large amounts of nitrogen to increase hydrocarbon recovery as well as to maintain reservoir pressure. Some of the fields with reservoir characterizations had been presented in literature (Clancy and Gilchrist 1983). In these fields, gas condensate/volatile oil was initially produced driven by gas expansion, supplemented by solution-gas and some with aquifer. After initial production, dry gas-re-injection and nitrogen injection was implemented. The experience associated with nitrogen injection and characteristics of reservoir development are valuable information for future nitrogen injection projects. These fields are situated on the hanging wall of the Utah-Wyoming thrust belt, and they are producing from Upper Triassic-Lower Jurassic Nugget formation as shown in Figure 2. Some key parameters about the fields are compared in Table 1. A general stratigraphic description about the formations is presented in Figure 2. Some major fields such as PRU and ARE have been produced from the nugget formation which comprises Aeolian dune and inter-dune/sand-sheet sandstones with a stratigraphic thickness of approximately 900ft (Ring et al. 1999). The reservoir fluids are gas with volatile oil, and gas condensate, respectively. A brief introduction about reservoir characteristics is as follows.

Overpressure gas reservoirs with close-boundary typically have downward curving in p/z plot. The overestimations of original gas in place (OGIP) caused by incorrect extrapolations of early production data are often observed in reserve evaluation. To eliminate this error, a comprehensive compressibility term that includes the rock compressibility, water compressibility, and gas solubility in water has been introduced into the p/z plot. To satisfy the above objective, it's critical to obtain the right average reservoir pressure corresponding to the drained gas reserve at the time point. But for overpressure gas reservoirs, if we completely ignore the permeability changes as the reservoir pressure declines, the reservoir performance cannot be representative. Another substantial deficiency of the conventional method is that the solution gas in connate water is also habitually neglected in estimating the OGIP. As a result, the contribution of solution gas to the total gas production is omitted in the material balance equation (MBE). These lead to the inaccurate estimation of the OGIP and gas reserve. Considering the permeability is not constant throughout the reservoir life, but a function of pressure, rock and fluid properties, production volume, and original pore volume, a new form of MBE is presented by this study. It includes the effects of the permeability change due to pore compaction and the contribution of solution gas in connate water to the total gas production. With the proposed semi-analytical equations, the average reservoir pressure and reservoir deliverability can be estimated accurately. Therefore the evaluations of OOIP and recoverable gas are more reliable.

Abstract Forchheimer equation takes non-Darcy flow effect into account in the event of high flow velocity in porous media. Its application requires both permeability, which is in linear term, and Beta factor, which is in quadratic term. Permeability and Beta factor are determined by rock type, textural of rock, effective porosity, pore throat size, geometry of the pore, and connection and distribution of pores. Beta factor comes into play when the fluid flow rate is high and the flow rate deviates from Darcy's law. Non-Darcy flow is described by Forchheimer equation. Usually the coefficient of non-Darcy flow term is hard to be determined. Existing approaches are core measurement and empirical correlations. To the best of our knowledge there is notheoretical equation available. To get an accurate estimation of flow rate or pressure drop in the reservoir, we need a method that has solid theoretical basis. The deficiency triggered our study. Starting from multiple-capillary tubes concept, we derived a rigorous relationship between pores geometry and pressure drop required for fluid flow through the pores. Through this correlation pressure drop can be calculated from known pores geometry. Since pores geometry can be often obtained from lab experiment or well logging, the new correlation also provides a unique approach to quantify the coefficient of quadratic term in Forchheimer equation. In this study we developed a governing equation through a rigorous theoretical derivation. With this equation the non-Darcy flow coefficient in Forchheimer equation can be calculated. The required input data for the new equation are readily obtained from well log interpretation. The new equation is a powerful tool in the event of no experimental measured non-Darcy flow coefficient available. It eliminates the errors or the arbitrary content in the empirical correlations.

Water influx is an important factor which needs to be quantified during early stages of reservoir development to justify project economics. For a CBM reservoir, it is much more important to quantify a degree of connection & boundary between coal reservoir and aquifer (if any) as its production mechanism is based on efficient dewatering process and any communication of coal seams with adjacent aquifer layercan act as a major barrier for development. However, it is difficult to quantify water influx values early in field life as limited data is available from the reservoir; but pressure transient testing, usually done during exploratory stage can play a pivotal part in reservoir characterization. Currently, solutions exist for analyzing pressure falloff test reponses to quantify water influx in the reservoir in communication with an infinite aquifer. However, there can be cases with limited aquifer extent in which case the use of former solution would lead to wrong estimation of water influx communication. So we propose a new model to account for closed outer boundray of aquifer, and use of this model to estimate both aquifer extent and water influx quantification. Leaky aquifer models more accurately describe bottom water drive reservoirs as most of the time aquifer connection with the reservoir is not perfect (ΔPres. ≠ ΔPaquifer). It is extremely important to quantify connectivity between the aquifer and the main reservoir before going for full field development. The method presented in this paper can provide a much needed solution to quantify the aquifer reservoir connectivity and the aquifer extent for a reservoir with bottom water drive earlier in field life using pressure transient data. We demonstrate the robustness of the proposed method using synthetic example for a homogeneous single well radial reservoir.