Halliburton (United Kingdom)

Abstract The most common fallacy in the quest for the optimum stimulation treatment in shale plays across the country is to treat them all just like the Barnett Shale. There is no doubt that the Barnett Shale play in the Ft. Worth Basin is the "granddaddy" of shale plays and everyone wants their shale play to be "just like the Barnett Shale." The reality is that shale plays are similar to any other coalbed methane or tight sand play; each reservoir is unique and the stimulation and completion method should be determined based on its individual petrophysical attributes. The journey of selecting the completion style for an emerging shale play begins in the laboratory. An understanding of the mechanical rock properties and mineralogy is essential to help understand how the shale reservoir should be completed. Actual measurements of absorption-desorption isotherm, kerogen type, and volume are also critical pieces of information needed to find productive shale reservoirs. With this type of data available, significant correlations can be drawn by integrating the wireline log data as a tool to estimate the geochemical analysis. Thus, the wireline log analysis, once calibrated with core measurements, is a very useful tool in extending the reservoir understanding and stimulation design as one moves away from the wellbore where actual lab data was measured. A recent study was conducted to review a laboratory database representing principal shale mineralogy and wireline log data from many of the major shale plays. The results of this study revealed some statistically significant correlations between the wireline log analysis and measured mineralogy, acid solubility, and capillary suction time test results for shale reservoirs. A method was also derived to calculate mechanical rock properties from mineralogy. Understanding mineralogy and fluid sensitivity, especially for shale reservoirs, is essential in optimizing the completion and stimulation treatment for the unique attributes of each shale play. The results of this study have been in petrophysical models driven by wireline logs that are common in the industry to classify the shale by lithofacies, brittleness, and to emulate the lab measurement of acid solubility and capillary suction time test. This is the first step in determining if a particular shale is a viable resource, and which stimulation method will provide a stimulation treatment development and design. A systematic approach of validating the wireline log calculations with specialized core analysis and a little "tribal" knowledge can help move a play from concept to reality by minimizing the failures and shortening the learning cycle time associated with a commercially successful project.

Intracellular Ca2+ release and reuptake are essential for contraction and relaxation of normal heart muscle. Intracellular Ca2+ transients were recorded with aequorin during isometric contraction of myocardium from patients with end-stage heart failure. In contrast to controls, contractions and Ca2+ transients of muscles from failing hearts were markedly prolonged, and the Ca2+ transients exhibited 2 distinct components. Muscles from failing hearts showed a diminished capacity to restore low resting Ca2+ levels during diastole. These experiments provide the first direct evidence from actively contracting human myocardium that intracellular Ca2+ handling is abnormal and may cause systolic and diastolic dysfunction in heart failure.

An experimental study of the migration of dilute suspensions of particles in Poiseuille flow at Reynolds numbers $\hbox{\it Re}\,{=}\,67\hbox{--}1700$ was performed, with a few experiments performed at $\hbox{\it Re}$ up to 2400. The particles used in the majority of the experiments were neutrally buoyant spheres with diameters $d$ yielding a ratio of pipe to particle diameter in the range $D/d \,{=}\, 8\hbox{--}42$ . The volume fraction of solids was less than 1% in all cases studied. The results of G. Segré & A. Silberberg ( J. Fluid Mech. 14 , 136, 1962) have been extended to show that the tubular pinch effect in which particles accumulate on a narrow annulus is moved toward the wall as $\hbox{\it Re}$ increases. A careful comparison with asymptotic theory for Poiseuille flow in a channel was performed. Another inner annulus closer to the centre, and not predicted by this asymptotic theory, was observed at elevated $\hbox{\it Re}$ . As $\hbox{\it Re}$ is increased, the distribution of particles over the cross-section of the tube at the measurement location, lying at a distance $L \doteq 310 D$ from the entrance, changes from one centred at the annulus predicted by the theory to one with the particles primarily on the inner annulus. The case of slightly non-neutrally buoyant particles was also investigated. A particle trajectory simulation based on asymptotic theory was performed to facilitate the comparison of theory and the experimental observations.

Abstract Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi-stage completions, innovative fracturing and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra-low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs supports both the modelling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results. Introduction Unconventional reservoirs provide a significant fraction of gas production in North America and increasing amounts in some other regions of the world. Such reservoirs include tight gas sands, coalbed methane (CBM), and gas shales; in 2006 these reservoirs provided 43% of the US production of natural gas [Kuuskraa(1)]. Because of their limited permeability, which is foremost among many other complexities, some type of stimulation process (and/or dewatering in the case of CBM) is required to engender economic recovery from wells drilled into these formations. The focus of this paper is on gas shales, with particular emphasis on how these reservoirs perform relative to tight gas sands. The important role of natural fractures in both the stimulation and production processes, the importance of conductivity in the developed fracture or fracture system, and the critical influence of the matrix permeability are investigated using both mapping and modeling results.

Charged with ensuring that research produces useful evidence to inform health decisions, the Patient-Centered Outcomes Research Institute (PCORI) requires investigators to engage patients and other health care stakeholders, such as clinicians and payers, in the research process. Many PCORI studies result in articles published in peer-reviewed journals that detail research findings and engagement's role in research. To inform practices for engaging patients and others as research partners, we analyzed 126 articles that described engagement approaches and contributions to research. PCORI projects engaged patients and others as consultants and collaborators in determining the study design, selecting study outcomes, tailoring interventions to meet patients' needs and preferences, and enrolling participants. Many articles reported that engagement provided valuable contributions to research feasibility, acceptability, rigor, and relevance, while a few noted trade-offs of engagement. The findings suggest that engagement can support more relevant research through better alignment with patients' and clinicians' real-world needs and concerns.

Summary Much public discourse has taken place regarding hydraulic-fracture growth and whether fractures could potentially grow up to the surface and create communication pathways for frac fluids or produced hydrocarbons to pollute groundwater supplies. Real fracture-growth data mapped during thousands of fracturing treatments are presented along with the reported aquifer depths in the vicinity of the fractured wells. These data are supplemented with an in-depth discussion of fracture-growth limiting mechanisms augmented by mineback tests and other studies performed to visually examine hydraulic fractures. These height-growth limiting mechanisms, which are supported by the mapping data, provide insight into why hydraulic fractures are longer laterally and more constrained vertically. This information can be used to improve models, optimize fracturing, and provide definitive data for engineers, regulators, and interest groups.

Summary In preparation for the SPE Applied Technology Workshop (ATW) held in Brugge in June 2008, a unique benchmark project was organized to test the combined use of waterflooding-optimization and history-matching methods in a closed-loop workflow. The benchmark was organized in the form of an interactive competition during the months preceding the ATW. The goal set for the exercise was to create a set of history-matched reservoir models and then to find an optimal waterflooding strategy for an oil field containing 20 producers and 10 injectors that can each be controlled by three inflow-control valves (ICVs). A synthetic data set was made available to the participants by TNO, consisting of well-log data, the structure of the reservoir, 10 years of production data, inverted time-lapse seismic data, and other information necessary for the exercise. The parameters to be estimated during the history match were permeability, porosity, and net-to gross- (NTG) thickness ratio. The optimized production strategy was tested on a synthetic truth model developed by TNO, which was also used to generate the production data and inverted time-lapse seismic. Because of time and practical constraints, a full closed-loop exercise was not possible; however, the participants could obtain the response to their production strategy after 10 years, update their models, and resubmit a revised production strategy for the final 10 years of production. In total, nine groups participated in the exercise. The spread of the net present value (NPV) obtained by the different participants is on the order of 10%. The highest result that was obtained is only 3% below the optimized case determined for the known truth field. Although not an objective of this exercise, it was shown that the increase in NPV as a result of having three control intervals per well instead of one was considerable (approximately 20%). The results also showed that the NPV achieved with the flooding strategy that was updated after additional production data became available was consistently higher than before the data became available.

Fundamentals of Drilling Engineering , an update of the classic Applied Drilling Engineering (Textbook Series Vol. 2), takes a new look at the basics of drilling engineering. Chapters are written by experts from industry and academia and provide numerous example problems to reinforce the concepts presented. This book is essential for undergraduate and graduate students, as well as industry professionals trying to gain detailed knowledge of basic drilling concepts.

Summary Observation of the sudden appearance of annular pressure in wells exposed to high temperature changes or excessive internal casing pressure prompted a laboratory investigation to simulate conditions under which cement sheath failure could occur and thereby define the causes, characteristics, and limits of the problem. Cement sheath failure is manifested by interzonal problem. Cement sheath failure is manifested by interzonal annular-fluid movement and abnormally high annular pressure at some point behind the casing up to and at the surface. Cement sheath point behind the casing up to and at the surface. Cement sheath failure can be observed in any producing area where excessive flowing temperatures exist at the surface or where excessive internal casing test pressures are used. The detrimental effects of cement sheath failure are numerous and may include lost revenue from lost production, potentially hazardous rig operations (especially when annular isolation loss creates shallow-water sands supercharged with gas), and potentially hazardous producing operations. Exposure of steel casing to excessive temperature increases or internal test pressures causes diametrical and circumferential casing expansion. This circumferential force creates a shearing force at the cement/casing interface, causing failure at the cement/casing interface or radial fracturing of the cement sheath from the inner casing surface to the outer casing (or borehole) surface.

Two ancestral clades of arbuscular mycorrhizal fungal species were discovered from deeply divergent ribosomal DNA sequences. They are classified here as two new families Archaeosporaceae and Paraglomaceae. Each family is phylogenetically distant from each other and from other glomalean families, despite similarities in mycorrhizal morphology and fatty acid profiles. Shared mycorrhizal morphology is not surprising, since it is highly conserved and resolves other taxa in Glomales at both family and suborder levels. At the present time, each family consists of one genus. Archaeospora (Archaeosporaceae) includes three species forming atypical Acaulospora-like spores from sporiferous saccules. Two of these species are dimorphic, forming Glomus-like spores as well. Paraglomus (Paraglomaceae) consists of two species forming spores indistinguishable from those of Glomus species. Morphological characters once considered unique, such as the sporiferous saccule defining species of Acaulosporaceae, clearly are distributed in phylogenetically distant groups. The simple design of spores of some species in Glomus also masks considerable divergence at the molecular level. It is the combination of DNA sequences, fatty acid profiles, immunological reactions against specific monoclonal antibodies, and mycorrhizal morphology which provides the basis for recognizing Archaeospora and Paraglomus. These results reinforce the value of molecular data sets in providing a clearer understanding of phylogenetic relationships, which in turn can lead to a more robust taxonomy.

Summary Since the introduction of the G-function derivative analysis, prefrac diagnostic injection tests have become a valuable and commonly used technique. Unfortunately, the technique is frequently misapplied or misinterpreted, leading to confusion and misdiagnosis of fracturing parameters. This paper presents a consistent method of analysis of the G-function, its derivatives, and its relationship to other diagnostic techniques including square-root(time) and log(∆pwf)-log(∆t) plots and their appropriate diagnostic derivatives. Four field test examples are given for the most common diagnostic curve signatures. These show how multiple analysis methods can be applied to consistently interpret closure pressure and time, as well as pre- and post-closure flow regimes and reservoir properties from the test data. The cases include normal constant-area and constant permeability leakoff, pressure dependent fissure leakoff, fracture tip extension, and variable fracture storage. In some cases conventionally accepted analysis methods, such as the Sqrt(time) plot, can lead to misleading interpretations. A single consistent approach to analysis is described for each case. The example cases can be used to build a foundation for consistent and less ambiguous analysis of any complex fracture injection/falloff test.

Summary Analysis of field and laboratory data shows that variations in pressure drop caused by changing perforation-entry friction tends to influence the prediction of fracturing treatment performance. This paper presents experimental data on perforation-entry friction as it affects fracturing treatment design. Prefracturing treatment planning practices include examination of numerous treating-pressure charts to determine formation type curves, which are used to anticipate fracturing treatment performance and screenout modes. Perforation-entry friction may vary greatly because of erosion of the perforation and new-wellbore fracture, and this changing friction pressure is often not properly accounted for in planning. This paper presents discussion and data (laboratory and field) that show the degree of perforation erosion encountered in fracturing operations and proposed guidelines to determine when to alter pumping schedules to account for proppant erosion to perforations, cement sheath, and formation. Introduction Fluid rheology measurements, densimeters, and flowmeters, combined with recent advances in computing power, allow determination of bottomhole treating pressure (BHTP), pbht on a real-time basis. This pressure is actually the BHTP inside the casing. The true BHTP is the pressure inside the fracture. BHTP and formation bottomhole pressure (BHP) are used interchangeably. The missing link and principal unknown in hydraulic fracturing is fracture-entry friction, pfef. It is usually assumed to be equal to zero, to be a constant, or to be a negligible influence on fracture treating pressure. Fracture-entry friction is the total pressure drop experienced by the fluid from the casing through the perforation and perforation tunnel to the fracture tip. Perforation friction, pf, is the pressure drop of the fluid passing through the restriction of the perforation in the casing. Current technology can determine the fracturing pressure in the casing but may not properly account for the changing BHTP caused by changing pfef. This paper addresses the changing pfef that occurs during pumping of sand-laden slurries. Pioneering work by Nolte and Smith1 created increased industry awareness of the necessity for accurately determining formation BHP during a fracturing treatment. In an extension of Nolte and Smith's work. Conway et al.2 proposed the analysis and use of treating-pressure type curves to predict well type and screenout mode during the treatment. Many hydrocarbon zones are bounded by a delicate boundary layer that may be fractured by pressure a few hundred psi over design pressure. Analysis of the Nolte and Smith plot is used to determine whether the fracture has broken out of zone. Changing (decreasing) perforation friction pressure during a treatment can be interpreted on a Nolte and Smith plot as evidence of breaking out of zone. Eq. 1 is used to calculate BHTP:Equation 1 wherepbht=BHTP,pw=wellhead pressure.ph=hydrostatic pressure.pt=pressure caused by fluid friction in tubulars, andpfef=pressure caused by fracture-entry friction. Two calculated values are present in this equation, pt and pfef. Several recent papers3–5 described means by which the calculation of pt can be improved, particularly in the case of sand-laden slurries. Components of fracture-entry friction include perforation friction, cetnent-sheath friction, formation damage (resulting from perforating), and fracture friction. Fracture friction can be calculated and depends on the fracture treatment design and fracture width. Formation damage can be minimized by shooting under-balanced,6,7 by proper design of perforation schedule, and by remedial acid cleanup jobs. Cement-sheath friction owing to perforating damage and its erosive properties is shown to have only a minor effect on total perforation-entry friction when slurries are pumped. The major component of pfef is pf, which is detailed below. The other components of pfef are minor constituents. When sand-laden slurries are pumped at high differential pressure across perforations, pf changes constantly. Field and laboratory data have been combined to derive coefficients theoretically and empirically and to check this equation. The equation commonly used to predict pf isEquation 2 whereq=total flow rate,?=fluid density.np=number of perforations.d=perforation diameter, andKd=discharge coefficient. Erosion of perforations in tubular goods and the subsequent drop in pf are the main points of emphasis in this paper. Laboratory data show that perforation-friction changes alone can cause errors in interpretation of Nolte and Smith plots. Experimental Apparatus. Three series of tests were run that pumped sand-laden slurries through perforated casing. Sand slurries are referred to by their concentration - i.e., pounds of sand per gallon of gelled fluid. Sand concentrations varied from 2 to 20 lbm/gal [240 to 2400 kg/m3], and differential pressure across the perforations ranged up to 1,500 psi [10.4 MPa]. Apparatus. Three series of tests were run that pumped sand-laden slurries through perforated casing. Sand slurries are referred to by their concentration - i.e., pounds of sand per gallon of gelled fluid. Sand concentrations varied from 2 to 20 lbm/gal [240 to 2400 kg/m3], and differential pressure across the perforations ranged up to 1,500 psi [10.4 MPa].

Abstract This paper reports theoretical and experimental developments involving propagation of hydraulic fractures in layered formations. Unobstructed fractures are shown experimentally to propagate with a decreasing fracturing fluid pressure. This general trend is in agreement with pressure. This general trend is in agreement with theoretical predictions. Restrictions in fracture propagation result in an increase in fluid pressure. propagation result in an increase in fluid pressure. The relative fracturability of rocks can be determined by a direct experiment, the results of which are clear, easy to interpret, and include all pertinent parameters, such as physical and pertinent parameters, such as physical and mechanical properties of rocks, as well as the reactions between formation and fracturing fluid (for example, leak-off). Fracturing experiments with layered samples show that with strong bonding between rocks it is difficult to contain a fracture in a formation totally. The strength of the interface between adjacent formations is shown theoretically to be an important factor in fracture containment. With a weak bonding, fracture containment is possible and is associated with slippage at the interface. The pattern of propagation then will depend on the relative propagation then will depend on the relative mechanical properties of fractured formations. Introduction Most industrial hydraulic fractures are created in layered formations. During propagation, these fractures encounter various formations with different physical and mechanical properties. This paper physical and mechanical properties. This paper discusses the effect of those properties on propagation of the fracture. propagation of the fracture.Most of the theoretical studies on fracture propagation have been extensions of Griffith's propagation have been extensions of Griffith's work. Based on an energy criterion, Griffith developed a relationship among fracture shape, material properties, and the external force needed for fracture propagation. The energy source in hydraulic fracturing is the fluid pressure inside the fracture. The relationship between this pressure and material properties is (1) (2) in which L = fracture extent (length of a two-dimensionalfracture or radius of a penny-shapedfracture) E = Young's modulus of material mu = Poisson's ratio of material gamma = effective fracture surface energy of material sigma = least in-situ principal stress A similar equation for a three-dimensional fracture is derived in Appendix A in the form of (3) in which hf = fracture height E(k) = complete elliptic integral of the secondkind K(k) = complete elliptic integral of the first kind k = parameter of the elliptic integrals Eqs. 1 through 3 show p to decrease with increasing L (Fig. 1) As the fracture becomes larger, it needs less pressure for propagation. In deriving these equations, no allowance has been made for fluid leak-off into the formation. SPEJ P. 33

Abstract Much public discourse has taken place regarding hydraulic-fracture growth in unconventional reservoirs and whether fractures could potentially grow up to the surface and create communication pathways for frac fluids or produced hydrocarbons to pollute groundwater supplies. Real fracture-growth data mapped during thousands of fracturing treatments in unconventional reservoirs are presented along with the reported aquifer depths in the vicinity of the fractured wells. These data are supplemented with an in-depth discussion of fracture-growth limiting mechanisms augmented by mineback tests and other studies performed to visually examine hydraulic fractures. These height-growth limiting mechanisms, which are supported by the mapping data, provide insight into why hydraulic fractures are longer laterally and more constrained vertically. This information can be used to improve models, optimize fracturing, and provide definitive data for regulators and interest groups.

From a detailed survey and sampling study of corrugated massifs north of the Fifteen-Twenty Fracture Zone on the Mid-Atlantic Ridge, we demonstrate that their surfaces are low-angle detachment fault planes, as proposed but not previously verified. Spreading-direction–parallel striations on the massifs occur at wavelengths from kilometers to centimeters. Oriented drill-core samples from the striated surfaces are dominated by fault rocks with low-angle shear planes and highly deformed greenschist facies assemblages that include talc, chlorite, tremolite, and serpentine. Deformation was very localized and occurred in the brittle regime; no evidence is seen for ductile deformation of the footwall. Synkinematic emplacement of diabase dikes into the fault zone from an immediately subjacent gabbro pluton implies that the detachment must have been active as a low-angle fault surface at very shallow levels directly beneath the ridge axis. Strain localization occurred in response to the weakening of a range of hydrous secondary minerals at a very early stage and was highly efficient.

Abstract Horizontal wells drilled in tight formations are likely to be stimulated by acidizing and/or propped fracturing to increase productivity. Normally, to control the placement of induced fractures in these wells, they are completed for later stimulation, i.e., cement cased and perforated. Unlike vertical well fracturing, fractures in horizontal wells can be induced along, or inclined to, or crossing the horizontal section. This orientation depends on deviation of the horizontal section from the minimum stress direction. An experimental study of fracture geometry from horizontal wells at various well azimuth deviations was conducted. Experiments were performed by applying triaxial loading conditions to rock blocks 6 × 12 × 18 in. surrounding cased and perforated boreholes. The borehole directions varied from 0 to 90 degrees from the applied minimum stress. Also, length of perforated interval was the second variable parameter in this study. After each experiment, rock blocks were sawed to observe the shape of induced fracture. The study showed that fracture geometry near the horizontal well is controlled by well deviation and length of perforated interval. From a stimulation viewpoint, the combined effects of these two parameters, if not investigated beforehand, may cause critical problems during fracturing. Laboratory observations indicated the following stimulation related problems: Creation of multiple fractures from the same perforated interval.Created fractures are nonplanar, with rough walls.Communication of fluid between the perforated section and fracture can occur through small channels.Interference between fractures conducted from separate perforated interval. Based on this study several recommendations are presented to help eliminate some of these stimulation related problems.

Summary This paper presents experimental results related to hydraulic fracturing of a horizontal well, specifically the nonplanar fracture geometries resulting from fracture initiation and propagation. Experiments were designed to investigate nonplanar fracture geometries. This paper discusses how these nonplanar fractures can be responsible for premature screenout and excessive treatment pressure when a horizontal well is hydraulically fractured. Reasons for unsuccessful hydraulic fracturing treatments of a horizontal well are presented and recommendations to ensure clear communication channels between the wellbore and the fracture are given.

Abstract Unconventional natural gas systems include fractured shale gas (FSG), tight gas sands (TGS), basin center gas (BCG), shallow basin methane (SBM), and coalbed methane (CBM). Recently, more operators are focusing attention on shale reservoirs. The most notable shale play being developed in the north Texas region is the Barnett shale. This success has encouraged operators to investigate producing potential of the Woodford and Caney shales in Oklahoma. Shale plays are unique in that they often are both the source rock and producing rock contained in the same package. This duality leads to difficulty in log and reservoir interpretation. To date, conventional log interpretation has proved inadequate in identifying producing potential. Simply perforating areas of high porosity and pumping massive hydraulic fracture (MHF) treatments do not always yield commercial production results. Identifying areas of high producing potential using gamma ray, density, resistivity, and sonic transit time to locate high total organic carbon (TOC) has also yielded mixed production results. We believe the addition of mechanical properties of the rock can help identify shale intervals with a high propensity to contain natural fractures and a high probability to create a fracture network during hydraulic fracturing. We propose a linkage between the mechanical properties of the rock and the hydraulic fracture network created during a MHF treatment and the resulting production outcome. Desirable combinations of mechanical properties are selected to help locate areas in the shale that have a propensity to fracture as a network with sufficient aerial extent to impact production results. We use these mechanical properties in addition to TOC and porosity to select fracture initiation sites and give a qualitative assessment of producing capacity. In this paper, we describe calculated log parameters that illustrate this technique.

Laboratory tests show that in porous-permeable rock both vertical and horizontal hydraulic fractures are possible, and that the breakdown pressure is lower than in an impermeable but otherwise identical pressure is lower than in an impermeable but otherwise identical formation. The direction of vertical fractures and the magnitude of breakdown pressures can be predicted from theoretical considerations. Introduction Hydraulic fracturing is a stimulation method used by the petroleum industry to boost oilwell production. In an open-hole completion, the method consists of searing off a section of the well, injecting it with pressurized fluid, and raising the pressure until the pressurized fluid, and raising the pressure until the well fractures. The fracture is then extended by pumping in high volumes of water or other fluids; the pumping in high volumes of water or other fluids; the permeability of the formation is thus improved, often permeability of the formation is thus improved, often resulting in a substantial increase in oil output. However, not all fracturing jobs have been successful. Even today, 20 years after the method was introduced, no certain predictions can be made as to what critical pressure will be required to initiate a fracture, whether pressure will be required to initiate a fracture, whether it will be horizontal, vertical or inclined, what will be its direction, its length, its height, etc. Articles have been published on the theoretical relationship between the tectonic (in-situ) stresses and the hydraulic fracturing pressures, but no thorough attention has been paid to the stresses due to possible infiltration of the formation by the injected fluid. Haimson and, independently, Geertsma have pointed out that this fluid penetration may significantly affect the critical (breakdown) pressure. This paper presents the criteria for fracture initiation in porous-permeable materials by considering all the possible stress fields around the wellbore. There has been very little laboratory experimenting on hydraulic fracturing, and only few reports have been published. This paper summarizes some laboratory tests on hydrostone performed at the U. of Minnesota as a part of an extensive research program in hydraulic fracturing. The experimental set-up allowed for the application of three mutually perpendicular, unequal compressive loads on a cubical sample having a central vertical hole, thus realistically simulating principal tectonic stresses in the earth. The pressurization of the central hole until fracture occurred provided the value of the critical pressure. This value and the direction of the crack were then related to the simulated in-situ stresses. The purpose of the tests was to verify some of the theoretical predictions regarding the relationship between critical pressures and fracture directions vs tectonic stresses in porous rock. porous rock. Theory It is assumed that the rock is brittle, linearly elastic, homogeneous, isotropic and porous, and that the fluid flow through the pores obeys Darcy's law. It is also assumed that one of the principal tectonic stresses acts in a vertical direction, i.e., parallel with the axis of the wellbore. The total stresses around the wellbore can be found by superposing the three individual stress fields generated by: the three principal tectonic stresses, the pressurization of the open hole of the wellbore, and the fluid flow from the pressurized hole into the formation. pressurized hole into the formation. JPT P. 811

Summary An equation-of-state (EOS) -based compositional reservoir simulator, UT-COMP, is used to simulate both primary recovery and carbon dioxide (CO2) huff ‘n’ puff recovery in a shale matrix typical of the Bakken formation, to investigate the effect of reservoir heterogeneity on hydrocarbon recovery. Nonaqueous components are carefully lumped into seven pseudocomponents. Permeability fields with various heterogeneity and correlation lengths are generated. UT-COMP is able to solve the compositional model, despite the permeability difference between the fracture and matrix being six orders of magnitude. The effects of both primary recovery and CO2 huff ‘n’ puff recovery depend significantly on reservoir heterogeneity. In primary recovery, the recovery factor can be fit by a two-parameter exponential formula; higher heterogeneity reduces the rate coefficient in the formula. Permeability fields with identical or similar heterogeneity have similar rate coefficients, even if the correlation lengths are different, which implies that the recovery depends primarily on heterogeneity and is insensitive to correlation length. Multiple-cycle CO2 huff ‘n’ puff processes are simulated in both homogeneous and heterogeneous reservoirs. Recovery rate in the production stage rises to a peak value much higher than that in the primary recovery, and then declines dramatically. The peak recovery rate decreases with increasing huff ‘n’ puff cycles, resulting from depleted reservoir pressure and hydrocarbons. The final recovery factor in the huff ‘n’ puff recovery is lower than that in the primary recovery, because the incremental recovery in the production stage is unable to compensate the loss in the injection and shut-in stages. Use of a longer shut-in time does not help increase the recovery rate in the production stage, because CO2 migration into the shale matrix is very limited because of the low matrix permeability. Reservoir heterogeneity leads to a faster decline of recovery rate in the production stage.