Multiple Fracture Systems Research Articles

Enhanced delivery of amendments in contaminated low-permeability soils by hydraulic fracturing

In-situ remediation of contaminated low-permeability sites remains to be a critical challenge due to severe mass transfer limitations. This work developed an analytical model for enhanced in-situ remediation by hydraulic fracturing in low permeability sites, considering the mechanisms of convection, diffusion, adsorption, and degradation of amendments. In this model, amendment-filled fractures were conceptualized as mass release sources, with the release process controlled by a dissolution-diffusion equation. Combining the Laplace and Fourier-cosine transformation techniques, the semi-analytic solutions in the two-dimensional spatial domain were obtained and then validated by COMSOL Multiphysics 6.0. Based on this model, the influence range, effective longevity, degradability, amendment reserves, and fracture spacing design of reactive fractures were investigated. Results show that (1) three reaction zones with different degradability will potentially form around the reactive fractures; (2) a larger reservoir of amendments effectively increases the influence range and effective longevity of reactive fractures; (3) the synergy of multiple fracture systems outweigh the sum of individual fracture properties, but the reasonable spacing design is decisive; (4) ignoring adsorption in low-permeability site remediation may overestimate the influence range of reactive fractures, leading to remediation failure. This work comprehensively analyzed the properties of reactive fractures, providing practitioners with a reference for the enhanced remediation of low-permeability contaminated sites.

Modeling of rock multiple fractures system with a new contact algorithm and a novel approach for complex topology construction

Multiple fractures intersection induced by crack propagation and coalescence is extremely significant for revealing the fracturing essence and establishing mechanical models of natural rock with complex fracture network. A complex discrete interface dynamically adding algorithm (CDIDA) and a potential function-based fracture contact calculation method (PBFCC) are proposed for multiple fractures propagation with complex topology in rocks. Through combining fracture representation with dynamic cyclic “nodal splitting” and nodal assignment with local topological structure identification, CDIDA is proposed to dynamically construct the complex fracture network for the discrete interface approach. CDIDA is able to efficiently establish reasonable local interface topology as the premise of accurately calculating the interaction of multiple fracture systems. Noting that the line attributable to any fracture interfaces can be defined as a set of discrete points, PBFCC transforms the complex contact calculation into the equilibrium problem of these points connecting with hypothetical bonds. The constitutive relation of these bonds is based on a modified potential function, and it is changeable and movable according to the current fracture interface configuration. PBFCC avoids the computing problems such as setting prior contact pairs and contact detecting at each iteration, and is suitable for complex interface contact scenarios with large grid deformations. Moreover, PBFCC ensures that the complex interacting mechanical field calculation of the multiple fracture system is reduced to individual discrete point level, leading to the advantages of high efficiency and wide applicability. Based on the numerical implementation in Cellular Automata Software for engineering Rockmass fracturing process (CASRock), single edge fracture, collinear tensile fracture system, multiple fracture system and complex multiple fracture system simulations are provided to validate the efficiency and accuracy of the proposed methods.

Prediction of Fracture Opening Pressure in a Reservoir Based on Finite Element Numerical Simulation: A Case Study of the Second Member of the Lower Triassic Jialingjiang Formation in Puguang Area, Sichuan Basin, China

All stages of oil and gas exploration and development involve the study of in-situ stress. Since the traditional two-dimensional and three-dimensional homogeneous models can no longer fulfil the requirements of research and production, numerical simulation of the stress field has become an effective study method. In this study, we took the Jia 2 member in Puguang area as a case to establish a geological model and a mechanical model based on the tectonic framework and the distribution characteristics of the rock mechanical parameters, respectively, and loaded the model with the present-day in-situ stress state calculated from the logging data as the boundary conditions. The simulation results show that 1) the orientation of the maximum horizontal principal stress in the study area is near E-W, and the in-situ stress orientation is locally deflected due to the influence of faults; and 2) the magnitude of in-situ stress is predominantly affected by the burial depth and lithology, and the minimum horizontal principal stress, maximum horizontal principal stress, and differential stress are mainly concentrated in the ranges of 30–60, 50–80, and 10–40 MPa, respectively. We also analysed the opening sequence of the multiple fracture systems during development, using the present-day stress field model. The analysis revealed that the E-W fractures will open first, and the continuously increasing operating pressure will lead to formation breakdown, producing a fracture network.

Study of material removal behavior on R-plane of sapphire during ultra-precision machining based on modified slip-fracture model

In this paper, the modified slip/fracture activation model has been used in order to understand the mechanism of ductile-brittle transition on the R-plane of sapphire during ultra-precision machining by reflecting direction of resultant force. Anisotropic characteristics of crack morphology and ductility of machining depending on cutting direction were explained in detail with modified fracture cleavage and plastic deformation parameters. Through the analysis, it was concluded that crack morphologies were mainly determined by the interaction of multiple fracture systems activated while, critical depth of cut was determined by the dominant plastic deformation parameter. In addition to this, by using proportionality relationship between magnitude of resultant force and depth of cut in the ductile region, an empirical model for critical depth of cut was developed.

Study of convective-diffusive flow during CO2 sequestration in fractured heterogeneous saline aquifers

CO2 sequestration in naturally fractured saline aquifers is important to be studied. This paper investigates the convective-diffusive flow to study CO2 sequestration by dissolution in single and multi-fractured heterogeneous saline aquifers. The effect of fractures density, orientation, permeability, aperture and surface roughness on CO2 dissolution and propagation of density-driven fingers are investigated. The results indicate that a single fracture causes the growing density fingers to deviate towards the high permeability path of the fracture. Additionally, the higher vertical fracture orientation, aperture and permeability will lead to a higher CO2 storage. In the multiple fracture systems, matrix permeability has a dominant and positive effect on CO2 storage. Nevertheless, the effect of fractures properties such as fracture density, spacing, permeability, aperture and surface roughness on the CO2 storage are dependent on the fractures orientation. For instance, having fractures with rough surface can cause CO2 dissolution retardation in the aquifers with only vertical fractures. This study provides more insights into dissolution trapping of CO2 in fractured heterogeneous saline aquifers.

Numerical Investigation of the Time-Dependent and the Proppant Dominated Stress Shadow Effects in a Transverse Multiple Fracture System and Optimization

In this paper, a numerical study is conducted to investigate the stress shadow effects (stress reorientation and change) during hydraulic fracturing in a transverse multiple fracture system. A numerical model is used for the numerical study. It is a 3D model and can simulate the fracture operation from injection begin to full closure (fracture contact). Therefore, there is no need to assume the fracture geometry for the investigation of the stress shadow effects (unlike previous studies). In the numerical study, the first and second operations in a fictive transverse multiple fracture system are simulated, meanwhile the stress shadow effects and their influences on the propagation and proppant placement of the second fracture are investigated. According to the results, the following conclusions are discerned: (1) most proppants are located in the lower part of the reservoir, even below the perforation; (2) the stress shadow effects are time-dependent and proppant dominated; (3) the stress shadow effects affect the fracture propagation and the proppant placement of the second fracture, and also the fracture conductivity of the first fracture; (4) the time-dependent stress shadow effects can be divided into four phases, fracture enlargement, closure without proppant contact, closure with proppant contact and full closure; and (5) the superposition effect of the stress shadow in a transverse multiple fracture system exists. According to the conclusions, some optimizations are recommended.

Optimizing Spacing of Multistage-Fractured Horizontal Wells in Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171688, “Optimizing Spacing of Horizontal, Multistage-Fractured Wells in Gas Reservoirs,” by Maryam Alghannam and Zillur Rahim, Saudi Aramco, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. The growing demand for gas in Saudi Arabia and the availability of multistage-fracturing (MSF) horizontal-well technology have spurred the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently by use of MSF strongly depends on well spacing, especially for low-permeability reservoirs. This paper gives the recommended MSF horizontal-well spacing for several development scenarios in Saudi Arabian gas-reservoir environments. Theoretical Background There are four different flow regimes for multiple-fracture systems without wellbore storage: early linear, early radial, formation linear, and pseudoradial flow (Fig. 1). The initial flow period observed is the linear flow, where fluid flow toward the fractures in the formation is perpendicular to the fracture planes. This flow exists when each fracture behaves independently and most of the fluid entering the wellbore comes from the fractures (when the fracture-tip effects have not yet affected the pressure behavior). After the start of the flow into the fracture tips, the early radial flow develops while there is still no communication between fractures. This flow regime may occur briefly or it may not occur at all, depending on the fracture length and spacing. Subsequently, formation linear flow develops after the fracture interference has been felt and the flow becomes normal to the horizontal well. Finally, the pseudoradial-flow regime develops in the formation, where the flow appears radial toward the entire well/fracture system. During this flow period, the composite fracture system behaves as if it were a single fracture. The flow eventually will reach pseudosteady state when it hits the reservoir boundaries or interferes with surrounding wells. The rate at which the flow regime develops, from the start of production under transient conditions until it reaches reservoir depletion under pseudosteady state, is highly dependent on well spacing and well and reservoir characteristics.

Numerical study on hydraulic fracturing in different types of georeservoirs with consideration of H2M-coupled leak-off effects

With the increase in the world’s energy consumption and the change in climate, unconventional energy resources become more and more popular. Since geological formations of low or ultra-low permeability are usually involved, hydraulic fracturing is one of the most important tools for their exploitation. The objective of this paper is to investigate hydraulic fracturing and its hydro-mechanical influences on different types of georeservoirs, including tight gas, oil, and geothermal reservoirs. Based on the previous work of hydraulic fracturing simulation with FLAC3Dplus, the multi-phase multi-component flow simulator TOUGH2MP is coupled for the numerical study. A new coupling approach is designed with special consideration of the H2M-coupled process in different types of georeservoirs. For the simulation, a generic 3D ¼ model (200 × 300 × 200 m, consisting of 50 m caprock, 100 m reservoir formation, and 50 m base rock) is adopted. The simulations are run under comparable reservoir and operative conditions. The results show that fracture propagation and proppant concentration are comparable with a short period of slurry injection (80 min × 6 m3/min). The fracturing fluid does not penetrate deep into the formation. Due to the high compressibility of gas, the induced pore pressure is much lower than that in oil and geothermal reservoirs, although the final leak-off ratio is comparable. The hydraulic fracturing causes stress reorientation in georeservoirs. According to the criterion of 5° stress reorientation, the minimum fracture spacing for a multiple fracture system in the assumed geothermal reservoir is 73 m, while that in an oil and gas reservoir is 66 and 60 m, respectively. This work expands on the numerical simulator as well as the understanding of hydraulic fracturing in unconventional georeservoirs. The results of this study can be used further to optimize the fracture spacing in a multiple hydraulic fracture system in different reservoir types.

Mechanics of fluid‐driven fracture growth in naturally fractured reservoirs with simple network geometries

A numerical model has been developed for fluid‐driven opening mode fracture growth in a naturally fractured formation. The rock formation contains discrete deformable fractures, which are initially closed but conductive because of their preexisting apertures. Fluid flow that develops along fractures depends on fracture geometry defined by preexisting aperture distribution, offsets along a fracture path, and intersections of two or more fractures. The model couples fluid flow, elastic deformation, and frictional sliding to obtain the solution, which depends on the competition between fractures for permeability enhancement. The fractures can be opened by fluid pressure that exceeds the normal stress acting on them and by interactions with intersecting closed fractures experiencing Coulomb‐type frictional slip. The Newtonian fluid is assumed to flow through the conductive fractures according to a lubrication equation that relates the cube of an equivalent hydraulic aperture to fracture conductivity. The rock material is assumed to be impermeable and elastic. This paper provides the governing equations for the multiple fracture systems and the solution methods used. Flow distribution and fracture growth in conductive fracture sets are simulated for a range of geometric arrangements and hydraulic properties. Numerical results show that elastic interaction between fracture branches plays a controlling role in fluid migration, although initial apertures can give rise to a preferential fluid flow direction during the early stage. In the presence of offsets, fracture segments subject to strong compression are difficult to open hydraulically, and their resulting smaller permeability can increase overall upstream fracture pressure and opening. The patterns of fluid flow become more complicated if fractures intersect each other. A portion of injected fluid is lost into closed empty fractures that cut across the main hydraulic fracture, and this delays the pressure increases required for fracture growth past the crosscutting fracture. The nonlinear fluid loss rate depends on the geometric complexities of the fracture sets and on the fluid viscosity. Sometimes fracture growth can be accelerated by the fast fluid transport along an intersected, relatively conductive natural fracture.

DOLOMITIZATION AND RELATED FLUID EVOLUTION IN THE OLIGOCENE – MIOCENE ASMARI FORMATION, GACHSARAN AREA, SW IRAN: PETROGRAPHIC AND ISOTOPIC EVIDENCE

Petrographic and stable isotope investigations of Oligocene‐Miocene carbonates in the Asmari Formation from the Gachsaran oilfield and surrounding area in SW Iran indicate that the carbonates have been subjected to extensive diagenesis including calcite cementation and dolomitization. Diagenetic modification occurred in different diagenetic realms ranging from marine, meteoric and finally burial.Asmari carbonates were in general deposited in a ramp setting and are represented by intertidal to subtidal deposits together with lagoonal, shoal and low‐energy deposits formed below normal wave base. Lithofacies include bioclastic grainstones, ooidal and bioclastic, foraminiferal and intraclastic packstones, and mudstones. Multiple episodes of calcite cementation, dolomitization and fracturing have affected these rocks to varying degrees and control porosity. Four types of dolomites have been identified: microcrystalline matrix replacement dolomite (D1); fine to medium crystalline matrix replacement dolomite (D2); coarse crystalline saddle‐like dolomite cement (D3); and coarse crystalline zoned dolomite cement (D4).Microcrystalline dolomites (D1) (6–12 μm) replacing micrite, allochems and calcite cements in the mud‐supported facies prior to early compaction show δ18O and δ13C values of −4.01 to +1.02‰ VPDB and −0.30 to +4.08‰ VPDB, respectively. These values are slightly depleted with respect to postulated Oligocene‐Miocene marine carbonate values, suggesting their precipitation from seawater, partly altered by later fluids. The association of this type of dolomite with primary anhydrite in intertidal facies supports dolomitization by evaporative brines.Fine to medium crystalline matrix dolomites (D2) (20–60μm) occur mostly in grainstone facies and have relatively high porosities. These dolomites formed during early burial and could be considered as recrystallized forms of D1 dolomite. Their isotopic values overlap those of D1 dolomites, implying precipitation from similar early fluids, possibly altered by meteoric fluids.Coarse crystalline saddle‐like dolomites (D3) (200–300 μm) partially or completely occlude fractures and vugs. The vugs developed through the dissolution of carbonate components and rarely matrix carbonates, while fractures developed during Zagros folding in late Oligocene to early Miocene times.A final diagenetic episode is represented by the precipitation of coarse crystalline planar e‐s zoned dolomite (D4) (80–250 μm) that occurs in fractures and vugs and also replaces earlier dolomite and post‐dates stylolitization. Fluids responsible for the formation of D3 and D4 dolomites are affected by brine enrichment and increasing temperatures due to increasing burial.Reservoir porosity is dominated by microcrystalline pore spaces in muddy, dolomitized matrix and mouldic and vuggy porosity in grainstone. Porosity was significantly enhanced by the formation of multiple fracture systems.

Microbial life in deep granitic rock

Granitic rock has aquifers that run through faults and single or multiple fracture systems. They can orientate any way, vertically or horizontally and usually, only parts of hard rock fractures are water conducting. The remaining parts are filled by coatings of precipitated minerals, and clay and gouge material. Sampling hard rock is difficult and the risk of contamination due to intrusion of drilling fluids and cuttings in aquifers is obvious. A recent investigation of the potential for contamination of boreholes in granite during drilling operations, using molecular and growth methods, showed that predominating microorganisms in the drilling equipment were absent in groundwater from the drilled boreholes. The total number of bacteria found in subterranean granitic environments ranges from 103 up to 107 cells per ml groundwater, but the number of cultivable microorganisms is usually much lower. We have used culturing techniques with numeric taxonomy for the identification of cultivable microorganisms and the 16S rRNA gene technique to determine bacterial diversity in granitic groundwater. Members of the genera Bacillus, Desulfovibrio, Desulfomicrobium, Eubacterium, Methanomicrobium, Pseudomonas, Serratia and Shewanella have been found. Several biogeochemical processes in granitic rock have been demonstrated where microorganisms seem to be of major importance. One process is the mobilization of solid phase ferric iron oxy-hydroxides to liquid phase ferrous iron by iron reducing bacteria with organic carbon as electron donor. Another biogeochemical process found to be important is the reduction of sulfate to sulfide by sulfate reducing bacteria. They frequently appear in granitic aquifers at depths, and seem to prefer a moderate salinity, approximately 1%. When groundwater rich in ferrous iron, manganese(II) and reduced sulfur compounds reaches an oxygenated atmosphere such as an open tunnel, gradients suitable for chemolithotrophic bacteria develop. A third process is the conversion of carbon dioxide to organic material with hydrogen as the source of energy, possibly formed through radiolysis, mineral reactions or by volcanic activity. Recent results show that autotrophic methanogens, acetogenic bacteria and acetoclastic methanogens all are present and active in deep granitic rock. These observations announce the existence of a hydrogen driven deep biosphere in crystalline bedrock that is independent of photosynthesis. If this hypothesis is true, life may have been present and active deep down in the earth for a very long time, and it cannot be excluded that the place for the origin of life was a deep subterranean igneous rock environment (probably hot with a high pressure) rather than a surface environment.

Microbial life in deep granitic rock

Granitic rock has aquifers that run through faults and single or multiple fracture systems. They can orientate any way, vertically or horizontally and usually, only parts of hard rock fractures are water conducting. The remaining parts are filled by coatings of precipitated minerals, and clay and gouge material. Sampling hard rock is difficult and the risk of contamination due to intrusion of drilling fluids and cuttings in aquifers is obvious. A recent investigation of the potential for contamination of boreholes in granite during drilling operations, using molecular and growth methods, showed that predominating microorganisms in the drilling equipment were absent in groundwater from the drilled boreholes. The total number of bacteria found in subterranean granitic environments ranges from 103 up to 107 cells per ml groundwater, but the number of cultivable microorganisms is usually much lower. We have used culturing techniques with numeric taxonomy for the identification of cultivable microorganisms and the 16S rRNA gene technique to determine bacterial diversity in granitic groundwater. Members of the genera Bacillus, Desulfovibrio, Desulfomicrobium, Eubacterium, Methanomicrobium, Pseudomonas, Serratia and Shewanella have been found. Several biogeochemical processes in granitic rock have been demonstrated where microorganisms seem to be of major importance. One process is the mobilization of solid phase ferric iron oxy-hydroxides to liquid phase ferrous iron by iron reducing bacteria with organic carbon as electron donor. Another biogeochemical process found to be important is the reduction of sulfate to sulfide by sulfate reducing bacteria. They frequently appear in granitic aquifers at depths, and seem to prefer a moderate salinity, approximately 1%. When groundwater rich in ferrous iron, manganese(II) and reduced sulfur compounds reaches an oxygenated atmosphere such as an open tunnel, gradients suitable for chemolithotrophic bacteria develop. A third process is the conversion of carbon dioxide to organic material with hydrogen as the source of energy, possibly formed through radiolysis, mineral reactions or by volcanic activity. Recent results show that autotrophic methanogens, acetogenic bacteria and acetoclastic methanogens all are present and active in deep granitic rock. These observations announce the existence of a hydrogen driven deep biosphere in crystalline bedrock that is independent of photosynthesis. If this hypothesis is true, life may have been present and active deep down in the earth for a very long time, and it cannot be excluded that the place for the origin of life was a deep subterranean igneous rock environment (probably hot with a high pressure) rather than a surface environment.

History Matching the Steam/Foam Injection Process In a Thick Athabasca Tar Sand Reservoir

Abstract Throughout the life of the Gregoire Lake In-Situ Steam Pilot (GLISP), a number of steps (i.e., steam stimulation, steam flooding, steam/foam injection, surfactant concentration reduction, pressure cycling, injection rate reduction and air/steam injection) were taken to develop and optimize the steam/foam injection process. After completing the project, a history match study was initiated to understand the process mechanisms and sensitive parameters. The ultimate purpose was to establish a steam/foam forecast model for the Athabasca tar sands. This paper presents the history match results and highlights the important process considerations that led to the final match. The model was validated by obtaining satisfactory predictions for other pilot producers. Overall, the empirical foam model was found to be adequate for field scale steam/foam simulation. The history match results confirmed that the communication path in the upper low oil saturation zone had a strong impact on the GLISP production performance and supported some of the operational decisions made by the project team during the pilot operation. The results also suggested that the steam/foam injection strategy could be further optimized. Introduction The Gregoire Lake In-Situ Steam Pilot (GLISP), a joint venture between AOSTRA. Amoco Canada and Petro-Canada (Phase A only) with Amoco being the operator, was the first steam/foam project conducted in the thick Athabasca tar sands. It successfully demonstrated the diversion of steam to the lower tar rich zone and resulted in improved bitumen recovery. The detail field history has been published by Sander et al.(1)This paper presents the most recent history match results based on techniques established in prior simulation studies.(2,3&4) A pilot well layout map is shown in Figure 1. The pilot consists of one injector (H6) and three producers (H3, H4 and H5) drilled in an inverted 4-spot pattern with an injector to producer distance of 46m. Three temperature observation wells (HO7, HO8 and HO9) were also drilled to obtain temperature information. The project was operated from October 1986 to July 1991. It was originally designed to create horizontal fractures in the rich tar zone to optimize steam flood heating. However, it was later found that a multiple fracture system was induced(5) and had led to steam overriding in the upper low oil saturation zone. A steam/foam diversion was thus initiated in October 1988 to mitigate the problem. Subsequently, additional tests were conducted to evaluate and optimize the process. The following summarizes the key pilot activities:Initial steam cycling to preheat the reservoir (October 1986 to July 1987).Steamflooding and occasional steam stimulation at production wells (July 1987 to September 1988).Steam/foam injection to mitigate the steam override effects (October 1988 to July 1989).Foam concentration reduction to optimize operating costs (August to December 1989).Injection pressure cycling, injection rate changes and air/steam injection to optimize the steam-oil ratio (January 1990 to July 1991). The objective of this paper was to match, as much as possible, the injection well bottomhole pressure, producer fluid rates and the observation well temperatures, with special emphasis given to the steamflood and foam injection periods.

The Denver Earthquake Sequence of March–April 1981

Abstract The Denver earthquake sequence of March–April 1981 was monitored by a network of four permanent and eight portable seismographs. In addition to the main shock (mb = 4.3) on 2 April, six microaftershocks (M < 2) during the subsequent two-week period were recorded and located. Five of those six events had epicenters within the most active area of the 1967–1968 Rocky Mountain Arsenal (RMA) sequence. A composite focal mechanism solution for the main shock and the six aftershocks showed a combination of reverse and strike-slip faulting (14% inconsistency in the 29 P-wave polarities) that is different from the predominantly normal faulting reported for the 1967–1968 RMA sequence. These different focal mechanisms, plus variable water-level response at the RMA well during the earthquake sequence in the 1960’s, may suggest the presence of a multiple fracture system in the source volume.

Comments on ‘Theory of heat extraction from fractured hot dry rock’ by A. C. Gringarten, P. A. Witherspoon, and Yuzo Ohnishi

The recent paper by Gringarten et al. (1975) points out the very significant result that the extraction of geothermal energy is much more efficient if the water passes through a multiple fracture system than if the water passes through a single fracture. In particular, their results show that a given flow rate divided among N fractures gives a higher outlet temperature over a period of time than if the same amount of fluid flows through a single fracture. It appears, however, that their model is unnecessarily complicated and hence the physical significance of the model may be partially obscured. For this reason it is shown that essentially the same results may be obtained by solving the heat transfer equation for a single fracture and by treating the geothermal system as a number of N independent, vertical fractures. (WDM)

Hydraulic Fracturing in Waterflood Operations in Kermit, Cherrykirk and Pecos Valley Fields

Abstract A limited amount of published data is available which presents results of hydraulic fracturing in waterflood operations. To add to this knowledge, this report presents data resulting from frac programs performed in three different reservoirs. These programs were performed to effect both injectivity and productivity increases. The majority of applications were performed at a time during flood life which affords valid and conclusive interpretation of results. Conclusions based upon results obtained from the frac jobs may or may nor be indicative of benefits to be gained in every field. Therefore, no panacea for lagging, negligible, or hesitant well performance is offered. However, it is suggested that sub par well performance in water flood operations may be alleviated and improved by proper applications of the popular hydraulic fracturing technique. A total of 20 producers and four injectors were treated in the three fields. Only two applications can be termed failures; these are believed to have been due to mechanical features (handout or improper frac technique). Theoretically, the most beneficial fracture system for flooding operations can be obtained by use of either low injection volumes and high injection rates or medium injection volumes and low injection rates. A resultant multiple fracture system of limited radial distance from the wellbore should occur. Introduction Requisite levels of well receptivity of productivity in waterflood operations are not necessarily incurred in every operation. Several factors attributable to local wellbore damage are possible causes. Until quite recently, no method to improve individual well performance, other than formation fracturing with explosives (nitroglycerin) or acidization, was considered safe enough to be used. Even these methods were unsure and often created expensive cleanout work after the shot.