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Summary Pseudo 3D (P3D) hydraulic fracturing models often overpredict fracture height for a poorly contained fracture. This is caused partly by either the neglect of the fluid flow component in the vertical direction or a crude treatment of the 2D fluid flow in the fracture as ID flow in the vertical direction in the fracture-height calculation. This paper presents a height-growth model that adopts a flow field more representative of the actual 2D flow in a fracture. In this model, the fracture is divided into two regions: an inner region where the flow direction is nearly horizontal, and an outer region where the flow field is approximated by a radial flow from an imaginary source. The governing equations for determining height growth rate and the numerical method for solving these equations are described. A commercial P3D simulator was modified by replacing its original height-growth model with this 2D flow-height model. The modified simulator was tested against the original simulator and the Terra Tek and U. of Texas fully 3D simulators. The modified P3D simulator incorporating the new height model showed significant improvement over the original model in height calculations and good agreement with the fully 3D models. Introduction Over the past decade, numerous 3D hydraulic-fracturing models have been developed. These models can predict fracture geometry, including height, with known reservoir parameters. The 3D models can be divided into two categories. The first type of models, often called P3D models, evolves from the 2D Perkins-Kern-Nordgren (PKN) model. Unlike the constant fracture height assumed in the PKN model, the height in a P3D model grows with time and varies along the pay-zone direction. The fluid flow in the fracture is assumed to be predominantly ID. The plane-strain condition is assumed on the deformation of each vertical fracture cross section. The other type of models, called fully 3D models, solves a set of coupled equations governing the deformation of a 3D fracture and the 2D fluid flow in the fracture. The fully 3D models are mathematically more rigorous but very complex and difficult to run. Different P3D models use different approaches to calculate fracture height and vary significantly in degree of complexity. The simplest approach is to determine height from the local net pressure, stress profile, and rock toughness by satisfying the static equilibrium of the fracture. The height thus obtained is the equilibrium fracture height. Fluid pressure is assumed constant over each vertical cross section, and the fluid flow is assumed to be in the pay-zone direction only.
- Well Completion > Hydraulic Fracturing (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.48)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.47)
- Well Drilling > Pressure Management > Well control (0.30)
Summary This paper elucidates the influence of pH and ion exchange on formation damage caused by fines migration. The experimental results affect waterflooding, design of drilling muds, and alkaline flooding. In-situ release of naturally existing fines (generally clays) results from changes in colloidal conditions of the permeating fluid. Such processes can cause extensive formation damage in sandstones, thereby reducing oil production. Our recent studies clearly indicate that the release process is started by a combination of high pH and low salinity. We present experimental results that suggest and confirm the interdependence between changes in salinity, cation exchange, and pH, leading to drastic permeability reductions. These results therefore provide new insight into the phenomenon of formation damage caused by water sensitivity or injection of incompatible brines. We also describe a unified approach to understanding these results and the findings of previous investigators. Predictions obtained from a physiochemical model based on ion exchange and colloidal chemistry agree well with experimental observations. The effect of different cations on formation damage also was investigated. This study can be extended to predict migration of bacteria and other particulates that cause formation damage. Introduction Khilar and Folger1 observed that the permeability of an initially brine-saturated Barea sandstone declines rapidly and drastically when the brine flow through the core is abruptly switched to fresh (deionized) or low-salinity water. Fig. 1 shows typical results. The abrupt change in salinity that leads to this drastic decline in permeability is called a "water shock," and the phenomenon is called "water sensitivity." Lever and Dawe 2 reported similar findings on a different sandstone. Permeability reduction is a serious problem in oilfield operations, such as waterflooding, and its control is essential for successful economic operations of oil and gas wells. Analysis of effluent samples from Barea sandstone after a water shock showed that permeability reduction results from blockage of fluid paths by submicron-sized fine particles, which are generally (kaelinite) clay.3 In the presence of brine, these particles (fines) are undisturbed and line the pore walls of the sandstone surface. When brought in contact with low-salinity water, the particles detach from the surface. The released fines migrate with flowing fluid and subsequently are captured at pore throats or pore constrictions, causing formation damage. The phenomenon of water sensitivity (i.e., reduction in permeability during a water shock) was explained by the Deryaguin-Landau-Verwey-Overbeek (DLVO) theory of colloids.3-6 such a permeability reduction also was observed when low-salinity brine replaced the initially permeating high-salinity brine. The concentration at which this permeability reduction begins is called the critical salt concentration and is analogous to the critical flocculation concentration of the DLVO theory for colloids.7 Such phenomena as migration of toxic waste from dump sites and failure of earthen embankments also are attributed to the process of fines migration,1,8 making the problem of water sensitivity of scientific and industrial importance. Background The two widely studied parameters that characterize the ionic conditions of the permeating fluid are salinity and pH. For brines composed of a mixture of ions, the mold ratios and the valency of the ions also become important.5,7,9 In this study, however, we limit ourselves to a 1:1 electrolyte. While a detailed review of earlier results is not possible here, we discuss them briefly to understand and contrast the current results with earlier published work.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.34)
Summary Although acidization has been used successfully for many years to increase the productivity of petroleum wells in carbonate formations, demands on the performance and application of the acidizing process are increasing. This study investigated a method of in-situ foam generation that allows deeper wormhole penetration yet uses less acid than conventional methods. The dissolution patterns were imaged with neutron radiography, which provided an in-depth understanding of the effects of foam and other critical parameters. Results show that foam is effective in promoting efficient stimulation, even at low acid injection rates. promoting efficient stimulation, even at low acid injection rates. Introduction The acidizing technique was patented in 1895. The first successful acid job was performed in 1932 on a limestone formation in Michigan. Since then, acidizing has remained an important part of petroleum engineering. The acidizing process involves injection of acid into a wellbore to dissolve some of the surrounding formation rock. This dissolution allows better inflow of formation fluids, easier injection of completion fluids, or easier injection during secondary recovery. Most carbonate acidizations today are performed with HCl plus a mixture of corrosion inhibitors, penetration fluids, and other chemical additives. HCl is a strong acid penetration fluids, and other chemical additives. HCl is a strong acid that is mass-transfer-limited in its reaction with limestone at temperatures above 32F. Consequently, the rate of spending is a function of the rate of injection, and at small injection rates, the acid penetrates only a limited depth before consumption. This in turn causes excessive dissolution near the wellbore and prevents deep stimulation. The most obvious solution to this problem might appear to be the injection of acid at high rates. Pressure limitations, however, sometimes prevent high injection rates. More important, natural heterogeneities cause some formation zones to accept acid at very slow rates. These low-conductivity zones need stimulation the most. Various solutions to this problem have been proposed, most of which incorporate some method to slow the acid's reaction with the rock. Acetic and formic acid react with limestone at a slower rate than HCl because of lower H + concentration. Chemical inhibitors also have been formulated to slow the rate of HCl consumption. Hoefner and Fogler developed a stable acid microemulsion that retarded acid diffusion and thus allowed deeper penetration of live acid. Coreflood experiments with the microemulsion penetration of live acid. Coreflood experiments with the microemulsion produced a breakthrough after injection of about 1 acid PV. While this produced a breakthrough after injection of about 1 acid PV. While this technique demonstrated the ability to stimulate carbonates at low injection rates, more cost-effective methods are needed. This paper describes a method of acidizing in the presence of foam that allows deep stimulation yet uses less acid than previous techniques. The process begins with injection of an aqueous surfactant into a core sample. process begins with injection of an aqueous surfactant into a core sample. Foam is created during acidizing by injecting commingled acid (i.e., nitrogen and aqueous HCl injected simultaneously). Wormholes are formed by the same phenomena as in conventional acidizing, but the presence of foam prevents acid from spending outside the primary dissolution channel. prevents acid from spending outside the primary dissolution channel. Results show the formation of a conductive wormhole rather than dead-end branches. In addition, significant core-face erosion is not a problem, even at very low flow rates. Neutron radiographs were used to study the structure of the wormholes generated by this and other methods. The wormholes created with foam consistently show uniform thickness with very little branching from the primary channel. The long, thin channels indicate the efficiency of this primary channel. The long, thin channels indicate the efficiency of this method, with some experiments producing a channel breakthrough after injection of less than 0.2 PV of 3 N HCl. Background To understand the process of foamed acid stimulation, we must combine knowledge from two complex subjects: the transport of fluids through foam in porous media and the stochastic process of wormholing. The behavior of foam in porous media has been studied extensively. Research in carbonate acidizing has been more limited, although a fairly good understanding of the process has been gained in recent years. Few papers on the use of foams in stimulation contain results from actual acidizing experiments, and none of these papers demonstrates that foam can enhance the wormholing process. Some of the theories on these topics are discussed below. Foams in Porous Media. Foamed fluids have been used in the field for more than 2 decades. Included in the wide range of applications are leakoff control in fracture acidizing, mobility control in waterflooding, flow diversion, and profile modification. The ability of a foam to provide mobility control and to prevent leakoff has prompted many theoretical studies into the structure, mechanism of formation, and transport properties of foams in porous media. Of these topics, the transport of properties of foams in porous media. Of these topics, the transport of liquid through foam is of the most concern to this work. Foam exists in a porous medium as a two-phase system of gas and liquid. Liquid is generally the wetting phase and thus resides as a series of lamellae bridging across pore throats and as thin films on the rock's surface. Gas is a discontinuous phase, residing in the larger void spaces of the medium. The addition of a surfactant allows the foam to maintain a stable two-phase configuration in which the lamellae can break and reform during dynamic events. The texture of a foam refers to the number density of gas-phase bubbles. The quality of a foam is the volume percentage of the pore space occupied by the gas phase. Bernard et al. performed the initial work relating to liquid (water) transport through a foam and found that the liquid permeability of a porous medium does not depend on the foam structure but rather on only the fluid saturation. Thus, fluid leakoff could be prevented simply by the introduction of a second phase (e.g., gas). However, foams are generally considered to be especially effective in reducing liquid permeability because they provide a stable method of maintaining a low liquid saturation, even during the flow of surfactant-free water. Holm later showed that liquid flows through foam by means of continuous films and lamellae. The implication of this flow mechanism is that the smaller pores containing no foam (i.e., no gas) will carry the majority of the liquid flow. This concept contradicts single-phase models that proportion the amount of fluid flow to the diameter of channels in a porous medium. Carbonate Acidizing. The stimulation of a carbonate is very different from the process that occurs in sandstone, primarily because the entire matrix of a carbonate rock is reactive. As a result, carbonate acidizing causes the formation of large flow channels (relative to the pore size) in some portions of the rock, while other portions are unaffected. This type of portions of the rock, while other portions are unaffected. This type of dissolution is extremely heterogeneous. Because of their macroscopic size, these flow channels are highly conductive to fluid, thus increasing the effective permeability of the medium. In contrast, the stimulation of sandstone causes pore-scale dissolution throughout the matrix so that the permeability is increased more homogeneously. permeability is increased more homogeneously. SPEPE p. 350
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Summary Constant-height models, in the absence of significant barrier stresses, frequently overpredict fracture half-lengths. This has been a problem in the fracture design of the Frontier and Dakota formations in the Greater Green River basin. Both formations often experience unlimited fracture-height growth as a result of a lack of barrier-stress contrast. This paper presents some of the implications of uncontained fracture-height growth in these formations on fracture design through 2D and 3D fracture geometry modeling. The effects of the minimum in-situ-stress profile, Young's modulus profile, and fluid-loss contrast on the fracture geometry evolution are studied. Actual field example data from a Frontier well are used for the sensitivity analyses. Introduction The low-permeability gas formations in the Greater Green River basin are potential low-cost gas sources in the western U.S. for the 1990's. Two major producing formations in the area are the Dakota and Frontier formations of Early and Late Cretaceous Ages, respectively. The U.S. Geological Survey (USGS) estimates that these two formations contain more than 220 Tcf, maybe as much as 490 Tcf, of natural gas in place. The Federal Energy Regulatory Commission (FERC) designated the Frontier formation in this area as a tight gas formation and thus made it eligible for economic incentives. These incentives and the new pipeline connecting this area with the growing cogeneration and thermal EOR markets in California make this area ideal for major gas E&P activity in this decade.
- North America > United States > Wyoming (1.00)
- North America > United States > Utah (1.00)
- North America > United States > Colorado (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Sand Wash Basin (0.99)
- (28 more...)
Summary Tip screenout (TSO) fracturing is a means of creating greater proppedfracture widths and hence fracture conductivities than can be achieved byconventional fracture treatments. This allows more cost-effective stimulationsof higher-permeability reservoirs, especially where non-Darcy pressure lossesare significant. This paper presents a procedure to design TSO schedules andreviews field results from the Ravenspurn South gas field, which was developedbetween 1988 and 1989. Evidence is provided to support the view that TSOpressure responses are provided to support the view that TSO pressure responsesare indeed the result of processes occurring close to the fracture tip, ratherthan slurry-enhanced viscosity effects along the fracture length. Introduction The productivity increases that can be achieved by hydraulic fracturing inhigh-permeability reservoirs are strongly dependent on the created fractureconductivities. TSO fracturing enables substantially greater fracture aperturesto be achieved than by more traditional methods. It also has resulted insignificantly increased well performance in both oil and gas reservoirs. TSOfracturing involves continued slurry injection after the proppant has bridgedoff at the fracture tip, terminating fracture proppant has bridged off at thefracture tip, terminating fracture propagation. Further pumping causes thefracture to balloon, propagation. Further pumping causes the fracture toballoon, resulting in increased treating pressures, fluid storage. and fractureaperture. Unless carefully designed, such treatments may achieve only limitedaperture increases and may carry substantially increased risks of prematuretermination resulting from uncontrolled pressure rises. The first reported useof TSO fracturing concerned the stimulation of a very soft chalk formationwhere abnormally wide propped fractures were required to combat proppantembedment. propped fractures were required to combat proppant embedment. Thedeliberate use of TSO fracturing was independently recognized as havingconsiderable potential for stimulating higher-permeability reservoirs, theobjective being to maximize fracture conductivities rather than to combatembedment. Some have argued that the pressure responses ascribed to TSO's maysimply be the result of increased slurry viscosity as proppant concentrationsare increased in the fracture. Recent proppant concentrations are increased inthe fracture. Recent laboratory data and the field evidence presented in thispaper challenge this view (see Appendix A). TSO fracturing has been appliedsuccessfully to the Ravenspurn South gas-field, resulting in up to seven-foldpseudo-steady-state productivity increases (relative to a prefracture skin ofzero), productivity increases (relative to a prefracture skin of zero), compared with three-fold increases for aggressive conventional treatments. Thedesign technique presented in this paper has recently been applied successfullyin the Prudhoe Bay oil field in Alaska. This paper presents a field-provenmethodology for designing high-conductivity hydraulic fractures, supported bythe results of an extensive fracture evaluation program conducted during thedevelopment of Ravenspurn South field. Productivity Increases Resulting From Fracturing Productivity Increases Resulting From Fracturing For a well completed without skin damage, theproductivity increase achievable by propped hydraulic fracturing is primarily afunction of the fracture's length and conductivity and the formationpermeability. A dimensionless measure of the fracture flow permeability. Adimensionless measure of the fracture flow capacity, CfD, is defined as (1) where kf (and k = fracture and formation permeabilities, respectively; bf =fracture aperture, and Lf = propped fracture half-length. Fig. 1 shows thepseudo-steady-state productivity increase, relative to an undamaged verticalwell, as a function of fracture Lf and CfD. While CfD less than 10, thefracture performance will be limited by insufficient conductivity. Consider a600-ft-long fracture in a gas reservoir with 2-md permeability. The effectivefracture conductivity, after allowing permeability. The effective fractureconductivity, after allowing for non-Darcy effects, would need to be 12,000md-ft to achieve CfD = 10. For a 150-ft-long fracture in a 50-md oil reservoir, a fracture conductivity of 75,000 md-ft would be required. Practical fieldexperience has shown that conductivities of this magnitude are rarely, if ever, achieved by conventional fracture treatments (see below). The following sectionillustrates that in high-permeability reservoirs. when conventional fracturedesigns are used, there is little scope for achieving major increases infracture conductivities. Alternative techniques are required. Fracture Length. Although increasing the fracture length will increase wellproductivity. this method will probably prove uneconomical unless accompaniedby adequate fracture conductivity. particularly in high-permeabilityreservoirs. particularly in high-permeability reservoirs. Fracture Conductivity. This is the key to cost-effective fracturing inhigher-permeability reservoirs. The following section briefly examines thefactors controlling the conductivities that can be achieved by conventionalfracture designs and demonstrates the need for alternative techniques toincrease propped fracture apertures. Fracture conductivity is defined as theproduct of the effective propped aperture and the effective proppant-packpermeability. The factors controlling these components are permeability. Thefactors controlling these components are discussed below. Aperture Controls. The effective propped aperture depends on the aperturecreated during pumping, the slurry concentration, and the loss of proppant fromembedment and gel residues. Created Aperture. There is limited scope toinfluence created aperture during fracture growth. Consider, for example, aconfined height fracture. While the fracture is propagating, doubling the pumprate, the viscosity, or the fracture length would each achieve only about a 20%increase in aperture, probably at significant additional cost, even ifpractical. Lost Aperture. Laboratory studies under Ravenspurn conditions showedthat at least 0.5 lbm/ft2 of proppant may be lost to proppant embedment intothe formation and the presence of unbroken proppant embedment into theformation and the presence of unbroken filter cake. In the muchhigher-permeability Prudhoe Bay reservoir, recent tests showed that up to 1lbm/ft2 may be lost. Aperture losses between 0.5 and 1 lbm/ft2 probably applyto many reservoirs, but there is little published information on the subject. Clearly, any part of the fracture where the proppant coverage does not exceedthe lost aperture will be ineffective. Propped Aperture. The higher the slurryconcentration in the fracture, the greater the proportion of the createdaperture that will be propped open. However, even increasing the proppantconcentration from 13 to 18 lbm/gal (clean) would only increase the proppedaperture from 47 % to 58 % of the created aperture, and at propped aperturefrom 47 % to 58 % of the created aperture, and at a significantly increasedrisk of a near-wellbore screenout. SPEPE P. 252
- Europe > United Kingdom > North Sea > Southern North Sea (1.00)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.74)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26 > Ravenspurn South Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26a > Ravenspurn North Field > Rotliegend Formation (0.99)
- (3 more...)
Summary Sixty-five percent of the reserves of the Kuparuk River field, thesecond-largest producing oil field in the U.S., is contained in a 20- to80-md-permeability sandstone. This paper provides details of stimulation designadvances made over the past provides details of stimulation design advancesmade over the past 3 years in this formation. The design steps for optimizingfracture treatments in a moderate-permeability formation require primaryemphasis on fracture conductivity rather than on treatment primary emphasis onfracture conductivity rather than on treatment size or fracture length. Thisphilosophy was used for the 140 new wells documented in this paper. Treatmentsize was gradually increased once a commensurate increase in fractureconductivity was obtained. Applying the new design to the refracturing of 88producing wells in the field resulted in an incremental 40,000 producing wellsin the field resulted in an incremental 40,000 BOPD, a significant portion ofthe field's 300,000 BOPD. Introduction During the past 6 years, more than 550 wells have been fracture stimulatedin the Kuparuk River Unit. The large number of treatments has provided theopportunity for significant advances in the technical and operational aspectsof hydraulically fracturing a moderate-permeability formation. The initialsuccess of this program was documented previously. 1 This paper outlines theprogram was documented previously. 1 This paper outlines the continuedtreatment optimization and the subsequent refracture treatments. As a result ofthe successful application of hydraulic fracturing, the economic developmentlimit of the Kuparuk River Unit has been extended significantly. The Kuparuk River Unit, located in the Alaskan arctic, covers. about 115,000 acres. Theinitial development is on 160-acre well spacing with some 80-acre infilllocations. The Kuparuk reservoir is a sandstone whose primary producingmechanism is solution-gas drive. The majority of the field is under secondaryrecovery, receiving pressure support through a combination of waterflood andwater-alternating-immiscible-gas injection. An enhanced recovery pilot, miscible enriched gas alternating with water injection, is pilot, miscibleenriched gas alternating with water injection, is under way. Production occursfrom two horizons within the Kuparuk sandstone. Fig. 1 is a typical log of the Kuparuk interval. The development's primary target was the upper zone, known asthe C Sand. It consists of very coarse to very fine-grained siderite- andquartz-cemented sandstone. Net pay ranges up to 80 ft, with an averagepermeability of 150 md. Fig. 2, a field map identifying the individualdrillsites, shows the areal extent of the C Sand in the Kuparuk River Unit. Since field startup in late 1981, the prolific rate of the C Sand zone hascontributed the majority of prolific rate of the C Sand zone has contributedthe majority of the field's production. The lower producing zone, the A Sand, is present throughout the unit. Although the average thickness is typicallyless than 30 ft, with permeability ranging from 20 to 80 md, the A Sandcontains 65% of the total reserves in the Kuparuk field. It is a fine to veryfine-grained sandstone interbedded with shale and cemented with quartz andvarying amounts of ankerite. The B Sand, made up of sands, siltstones, andshales, ranges in gross thickness from 0 to 150 ft. This high-shale-contentzone provides a barrier that is impermeable to flow between the two producingzones. This barrier benefits the oil recovery at Kuparuk by allowing the twozones of distinctly different producing characteristics to be waterfloodedseparately. It also provides the reservoir barrier to isolate and treat the ASand effectively by hydraulic fracturing. Kuparuk wells with departures up to9,000 ft are drilled from centrally located gravel pads to minimize theenvironmental impact in the arctic tundra. The majority of the wells aredrilled at an angle through the Kuparuk to minimize drilling costs. Untilrecently, no attempt was made to align the wellbore with the fractureorientation, and the typical hole angle across the formation is 40'. Fig. 3 isa typical 16-well drillsite development illustrating the central pad locationand the well departures. Interpretation of fracture treating pressures andheight growth is complicated by the deviated wellbores that require specialperforating and fracturing strategies. Two primary options are used to preventcommunication in the wellbore during the fracture treatment, depending on the CSand development. In the core of the field, where the C Sand is well-developed, selective single completions are installed to allow a packer to isolate the CSand. For the wells with minimal C Sand development, the A Sand is stimulatedgenerally before the C Sand is perforated. Fig. 4 shows completion schematicsof these two perforated. Fig. 4 shows completion schematics of these twocompletion practices. These completions allow zonal isolation to be maintainedduring fracture treatments, assist in managing waterflood operations, andimprove reserve recovery. The moderate-permeability A Sand has low initialrates. Unstimulated, it would be uneconomical in the high-cost arcticenvironment. Prefracture flow efficiencies average 55% (flow efficiency is theratio of the well's actual PI to its PI if the skin equals zero). Matrixstimulation treatments are unsuccessful because of the highly laminated natureof the A Sand, which prevents effective communication between the perforationsand all the sand intervals. Fracture treatments are used to overcome thenear-wellbore damage caused by drilling and completion operations and toprovide high-flow-capacity fractures to maximize withdrawals. The hydraulicfracture program allows the successful development of the reservoir andsignificantly expands the economic acreage of the Kuparuk River Unit. In thismoderate-permeability formation, the design challenges center around acombination of maximizing fracture width, proppant conductivity, and fracturelength while minimizing height growth and gel damage. The remote location andharsh environment require strong consideration of the operational aspects ofthe treatments to maximize overall success. Initial fracture treatments focusedprimarily on the near-wellbore damage. During the design evolution, a varietyof fluids, proppants, and pumping schedules were used to balance theoperational and theoretical design considerations. The standard design usedduring 1984-86 (Table 1) was about 11,000 lbm of 20/40-mesh sand, 200 bbl ofgelled diesel, and fluid-loss additives of silica flour and 100-mesh sand. Gelled diesel had the added benefits of minimizing formation damage andeliminating the freezing risks associated with gelled water. The majority ofthese treatments were performed initially in the southwestern portion of thefield and in older wells that were recompleted with selective single completiondesigns. This treatment design overcame damage caused by drilling andcompletion fluids, minimized the potential for communicating with the C Sand, and reduced screenout frequency. Typical postfracture production rates were 755BOPD with a flow efficiency of 153 %. New wells drilled during the past 4 yearsprovided the opportunity to optimize the Kuparuk fracturing program. The coreof the stimulation activity was the new development area in the northernportion of the field with minor C Sand development. SPEPE P. 259
- North America > United States > Alaska > North Slope Borough (1.00)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.44)
- North America > United States > Texas > East Texas Salt Basin (0.99)
- North America > United States > Louisiana > East Texas Salt Basin (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.99)
Summary This paper compares the steam stability of common gravel-packing materials. The scope was limited to one set of downhole conditions. Results indicated thatnone of the commonly used materials were entirely satisfactory, but anothermaterial not normally used in the petroleum industry was found to giveexcellent results. Introduction The chemistry of silica may be one of the most widely studied subjects inthe world. Iler's book contains more than 3,000 references. Perhaps it has beenso widely studied partially because it is one of the most abundant materials onearth and partially because its behavior is so enigmatic. partially because itsbehavior is so enigmatic. This paper focuses on the use of silica as agravel-packing material in wells that produce from an unconsolidated formationor as a proppant used to provide a high-permeability fracture path to thewellbore in lower-permeability consolidated path to the wellbore inlower-permeability consolidated formations. In gravel-packed wells that produceheavy oil from incompetent formations, the practice of injecting steam toenhance production is widespread. It has been found that under the conditionsat which steam is injected, typically pH 11 or higher and at temperatures up to600 degrees F, quartz sand dissolves fairly rapidly. Attempts to alleviate thisproblem by substituting other materials for sand have been described. Underdownand Das suggested high-alumina sintered bauxite; Sacuta et al. obtainedcontradictory results. Other studies showed that siliceous formations alsodissolve but at a lower rate because of impurities in the system. Presentstudies agree with Sacuta et al. that bauxite is not only Present studies agreewith Sacuta et al. that bauxite is not only soluble to a considerable extent inhigh-pH water, but also reprecipitates and fills in void spaces, decreasing thepack permeability. permeability. Specially graded quartz sand is the primaryproppant used in fracturing operations to stimulate production inlower-permeability, competent formations. Bauxite-type materials are used indeeper, harder formations to provide long-term, high fracture permeability. Fracturing techniques using both sand and bauxite to stimulate production ingeothermal formations have been described. production in geothermal formationshave been described. There is no reason to assume that successful fracturetreatments in geothermal wells are impossible because formation water isalready saturated with silica; the quartz proppant should have a lowsolubility. Evidence suggests that high temperature decreases the strength ofquartz proppants. Cosner and Apps showed silica contents from 4 to 1,416 ppm inwater samples from different formations and fields. The average concentrationwas between 200 and 300 ppm. No correlation between the pH of the water ortotal dissolved solids and the silica content was apparent. No analyticalmethods were described, sampling procedures varied widely, and the formationcomposition was not described. Reprecipitation of silica from highly saturatedformation water onto new silica surfaces is a real possibility. Also it isunlikely that the formation water would be saturated with alumina in mostinstances, so the possibility that bauxite will dissolve exists. A new proppantavoids the shortcomings of both sand and bauxite. Experimental Fig. 1 is a schematic of the test equipment used in this study. Equipmentincludes a reservoir of deionized water adjusted to pH 11 with reagent-gradesodium carbonate. CO2 was excluded by use of a trap containing Ascarite (TM)CO2 absorbent. Upsteam and downstream backpressure regulators were used tomaintain a differential pressure of 60 psi across the system, with an absolutesystem pressure of 60 psi across the system, with an absolute system pressureof about 1,200 psi. The regulation equipment was protected pressure of about1,200 psi. The regulation equipment was protected by the cold-water heatexchangers both up- and downstream. Test samples were contained in a section of0.375-in.-diameter tubing. Both the sample holder and the heat exchange coilwere submerged in a thermostatically controlled fluidized sand bath. The entiresystem was initially constructed of wetted Grade 316 stainless steel parts. Later studies used high-temperature wetted parts made of Monel (TM). parts madeof Monel (TM). Weight-loss data were obtained by weighing oven-dried, loadedtest cells before and after the tests. Note that this method does not accountfor any fines generated during the test and retained in the test cell, but onlymaterial actually produced from the cell. A computer data-acquisition systemwas used to determine pack permeability and to obtain 20-mL effluent sampleshourly. Some of permeability and to obtain 20-mL effluent samples hourly. Someof these were analyzed for Si, Al, and Zr. Discussion The initial objective of this study was to evaluate commercially availableproppants (Table 1) useful as gravel-packing materials forcyclic-steam-injection wells. These proppants also were to be considered forfracturing geothermal wells. This evaluation was to determine, under realisticconditions, the life expectancy of the packing material. Laboratory screeningconditions were selected to be representative. Most of the initial testing useda fluid temperature of 550 degrees F and pH of 11. A fluid velocity of about 4cm3/min was generally used, but it varied during the tests because a constantpressure differential was maintained. Three days of injection proved to besufficient for the evaluation of most materials. Table 2 gives the weight-lossresults of some of the materials evaluated. Sand gave the highest weight-lossvalue, losing 77% of its weight in three days. This weight loss was found to beproportional to fluid pH, temperature, and throughput volume. proportional tofluid pH, temperature, and throughput volume. Fig. 2 is a scanning electronmicroscope (SEM) micrograph of the sand sample after the 3-day test. Notice thesmooth surfaces and the absence of any fines, indicating complete and uniformsurface dissolution. Several alumina proppants and one zirconia-based proppant, which are reported to have superior crush resistances at high temperatures infracturing operations, were evaluated and found to be more stable than sandunder the harsh conditions of cyclic stream treatments. Table 2 gives resultsof stability tests on five popular, high-performance proppants used for gravelpacking cyclic-steam-injection wells. Table 2 shows analyses of thesematerials. In addition to weight-loss determinations, the concentrations ofsilica, alumina, and zirconia were monitored during the flow tests. In sometests, 20-mL effluent samples were obtained hourly and analyzed by atomicadsorption. Fig. 3 is an example of this type of data. For other tests, asingle sample of the total effluent was analyzed by atmoic adsorption to givean average value (Table 3). Weight-loss results after 3 days of flowing hotwater ranged from 37 to 60%. While this is an improvement over sand, it wasconsidered unsatisfactory for two additional reasons:the material cost ismuch higher (10 to 15 times) than the cost of sand and pack permeabilitydecreased dramatically. This is shown for one proppant in Fig. 4. Theunexpected loss in permeability has also been observed in field operations withthese types of proppant. Fig. 5 is a photograph of the one sample as it wasremoved from the flow cell photograph of the one sample as it was removed fromthe flow cell after a 3-day flow test. Copious quantities of fines wereevident. Some actual pack consolidation was observed.
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.34)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Summary In-situ growth of cellular material is known to cause formation damage. Bacterial reproduction and polysaccharide production are the key factors thatsegregate bacterial formation damage from fine and particulate damage. Carefully controlled experiments conducted on both high- and low-permeabilityceramic cores showed that bacteria can plug the pores and damage the cores. However, further experimentation demonstrated that polysaccharide production islargely responsible for this damage. This polysaccharide production is largelyresponsible for this damage. This conclusion is based on a comparison of twoexperimental systems: core plugging from bacterial replication and polymericproduction and plugging plugging from bacterial replication and polymericproduction and plugging of the porous medium caused solely by cell divisionwith no polysaccharide production. In light of these results, theinterpretation of reservoir production. In light of these results, theinterpretation of reservoir plugging resulting from the presence of bacteriarequires further scrutiny. plugging resulting from the presence of bacteriarequires further scrutiny. Introduction Bacterial growth will transport in reservoirs can greatly influence EOR. Bacteria can enhance recovery by producing gases (CO2 and H2) that increase thewell's internal pressure and decrease the viscosity of the crude oil (belowbubblepoint). In addition, in-situ cellular biosurfactant production has beenshown to be a viable technique to enhance oil yields by decreasing theinterfacial tension between the oil and the water, thus allowing better crudeemulsification. These two phenomena are but a few of the possiblebacteria/hydrocarbon interactions phenomena are but a few of the possiblebacteria/hydrocarbon interactions that can influence oil recovery. Thesephenomena have been given the collective name of microbial EOR (MEOR), atertiary oil recovery technique. The plugging of a water-swept zone by theinjection and cultivation of bacteria, in situ, has also been proposed as aneconomical technique for flow diversion. This technique would be initiated withthe injection of bacteria, suspended in a nutrient-rich medium, into thereservoir. Next, the well would be shut in to provide sufficient time formicrobial growth, hence plugging the high-permeability thief zones. Then waterinjection would be resumed and the plugged zone would divert the injectionwater into unswept zones. Rationale. Before any MEOR technique, such as in-situ surfactant and gasproduction or flow diversion, can be realized, a basic understanding of howbacteria are transported through porous media and how their retention affectsthe permeability of the media is needed. Bacterial transport through andretention by porous media differ from particle transport because cells increasein number and can produce polysaccharides, which affect their ability to adhereto surfaces. Bacterial adhesion experiments with inert nonporous surfacesdemonstrated the importance of polysaccharide production. These studies, however, considered only the effect of polysaccharides on cell adhesion toinert nonporous surfacer, and did not consider the effects of in-situ growth. Consequently, there is a lack of information on the effects of polysaccharideson cell transport and retention in porous media. This polysaccharides on celltransport and retention in porous media. This study, which is part of a seriesof experiments demonstrating bacterial cell transport and retention in porousmedia, was conducted to determine the effects of Poly-saccharide production onreservoir plugging. Background Bacterial Adhesion. It has been proposed that bacterial adhesion is atwo-step process. The first step is the reversible adsorption of bacteria tothe surface. This initial contact of the cell with the surface is dependent onthe colloidal, hydrodynamic, and inertial forces. Once the cell is adsorbed onthe surface, the second step begins with the polysaccharide production, leadingto the irreversible binding of the cell polysaccharide production, leading tothe irreversible binding of the cell to the surface. Fletcher et al. observedthe irreversible binding phenomenon in experiments on the adhesion of marinebacteria to filters. phenomenon in experiments on the adhesion of marinebacteria to filters. They discovered that it is not the cell's primary acidicpolysaccharide coating that irreversibly binds the cell to the surface, but theproduction of a secondary acidic polysaccharide the firmly attaches the cell. The primary polysaccharide helps in the initial adhesion of the cell by primarypolysaccharide helps in the initial adhesion of the cell by mediating afavorable contact between the cell and the surface. The secondarypolysaccharide, more fibrous reticular (net-like/tangled) substance, interconnects between and around adjacent bacteria or between bacteria and thesurface to attach the cell irreversibly. Fowler et al. demonstrated thisphenomenon by subjecting cells (attached to glass and stainless steel surfaces)to various shear stresses in a radial flow chamber. It was found that the shearstress required to suspend the sessile (attached) bacteria increases with thecontact time given to the cells for the adhesion. Bacterial Injection and In-Situ Growth. Earlier microbial transportexperiments used dead bacteria for core-injection studies. Typically, commonbacteria, such as Bacillus subtilis, were grown, killed by sterilization, andthen injected into a Berea sandstone core. Results from the injection of deadbacteria into the sandstone core indicated that bacteria would enter the porousmedium and be transported until they were sieved by a pore of smallerdimensions or captured according to deep-bed filtration mechanisms. Sieving isthe dominant capture mechanism that occurs within the inlet section of the coreduring the initial stages of bacterial injection. During injection of the ofthe dead bacteria, blocking the larger pores takes longer than blocking thesmaller pores because the bacteria must first agglomerage. This pluggingsequence produces the reverse-S-shaped curve when the permeability ratio, k/koproduces the reverse-S-shaped curve when the permeability ratio, k/ko (where ko= initial permeability of the core before cell injection), is plotted as afunction of time (or PV's injected) on the abscissa (Fig.1). plotted as afunction of time (or PV's injected) on the abscissa (Fig.1). In addition, theinjection of dead bacteria into Berea sandstone exhibited the development of anexternal filter cake at the injection face of the porous medium. porous medium. The injection of live bacteria into core samples also produces the typicalreverse-S-shaped permeability reduction curve. Closer examination of theseinjected core samples with a scanning electron microscope (SEM) have shown thatthe pores were plugged by bacteria coated with exocellular polysaccharide. Cores injected with dead cells, when examined by SEM polysaccharide. Coresinjected with dead cells, when examined by SEM techniques, did not demonstratethis phenomenon. In addition to these observations, the development of anexternal filter cake was noted during the injection of live cells. Once thebacteria enter the reservoir, they may grow in situ. This growth is dependenton the availability of nutrients within the reservoir. In secondary oilrecovery, where large volumes of water are injected into the reservoir, accelerated indigenous bacterial growth can be supported by the nutrients inthe injection water, thus causing near-wellbore plugging. Bright-fieldmicroscopic examination of test cores flood with samples of reservoir injectionwater (water known to contain bacteria and growth nutrients) indicated that thepores at the injection face of the cores become plugged owing to the capture, followed by the growth, of planktonic cells in the injection water. Accompanying the cells were large amounts of cellular polysaccharide.
- North America > United States > West Virginia (0.45)
- North America > United States > Pennsylvania (0.45)
- North America > United States > Ohio (0.45)
- North America > United States > Kentucky (0.45)
- Research Report > Experimental Study (0.68)
- Research Report > Strength High (0.54)
Summary A dynamic method is proposed for checking the stability of clay in porousmedia for different brine conditions and the stabilizing effect provided byseveral anionic and nonionic high-molecular-weight polymers. The methodconsists of injecting brine at decreasing salinity levels into clayey sandpacksuntil unstabilized permeability reduction is reached from the dislodging ofclay particles that become trapped in pore restrictions. The last stable statebefore clay destabilization is characterized by a critical salinityconcentration (CSC). As expected, montmorillonite clay 5% dispersed in asandpack is more stable in the presence of KCl than NaCl brines, giving CSCvalues of 5,000 and 27,500 ppm, respectively. Polyacrylamides are much betterclay stabilizers than carboxymethyl cellulose (CMC) or xanthan gum (XG), lowering the CSC of KCl to 1,000 to 2,000 ppm and the CSC of NaCl to 6,000 to7,000 ppm. A low-molecular-weight shear-degraded polyacrylamide is shown ppm. Alow-molecular-weight shear-degraded polyacrylamide is shown to keep goodstabilizing power without inducing the high permeability reduction valuesobtained after adsorption of high-molecular-weight products. In addition topreventing clay migration, polyacrylamides products. In addition to preventingclay migration, polyacrylamides are also shown to inhibit clay swelling. Introduction Contact between a foreign water and formation clays may induce severe claydestabilization problems. Clay hydration during drilling of shale layers maycause stuck pipe, wellbore instability, and solids buildup in the drillingfluid. When the foreign fluid invades a clayey reservoir zone, severe formationdamage may occur as a result of clay swelling, dislodging of clay particles, and the trapping of clay particles in pore particles, and the trapping of clayparticles in pore restrictions. Several stimulation operations enhance the riskof clay destabilization. Acidizing jobs can induce the release of fineparticles when the rocks contain a high percentage of clay. Steam or freshwaterinjection enhances clay destabilization, which can dramatically decrease wellinjectivity. Fracturing fluids may also adversely affect formation clays. Highclay sensitivity may call for the use of such non-aqueous fluids as oil, alcohol, or foam, but for environmental reasons, the current trend is to usewater as the base fluid and to add clay stabilizers to the water. Clay can bestabilized three ways: ion exchange, coating of clay particles, or modificationof surface affinity toward water. Ion Exchange. Because clay swelling and destabilization are enhanced when Na+ is the clay counter-ion, its replacement by other monovalent positive ions(such as NH4+, H+, or K+) is in effective way to increase clay stability. Potassium salts are used most extensively because of their efficiency, lowcost, and excellent brine compatibility. Monovalent ions, however, are known tohave a temporary effect. In the presence of brines with high NaClconcentrations, the stabilizing effect disappears progressively by the sameion-exchange process that leads to the progressively by the same ion-exchangeprocess that leads to the replacement of K + by Na + ions. More permanenteffects are obtained with cations having higher valences, such as Ca2+, Al3+, or Zr4+. The high positive charge of these ions makes them more strongly bondedto clay and not easily removable by other ions. Coating of Clay Particles. Adsorption of high-molecular-weight polymers isknown to prevent fine migration. The mechanism polymers is known to preventfine migration. The mechanism involved is the formation of polymer bridges thatmaintain clay particles linked together on the rock surface. Moreover, polymerparticles linked together on the rock surface. Moreover, polymer adsorption isalmost irreversible, so it produces a long-term effect. Anionic or nonionicpolymers have been among the first to be used: polyacrylamides with differentionicities, polyacrylates, CMC, carboxymethyl hydroxyethylcellulose, etc. Morerecently, cationic organic polymers (COP's), such as polyquaternary amines, have been shown to be excellent clay polyquaternary amines, have been shown tobe excellent clay stabilizers. We can include in this category inorganicpolymers, such as hydroxyaluminum, which, like the COP'S, combines a coatingeffect with the ionic effect of aluminum ions. Modification of Surface Affinity Toward Water. Adsorption of lipophilicadditives on a clay surface makes this surface less water-wet while decreasingits hydration tendency. This category of additives includes oil-wettingsurfactants, asphaltenes, and petroleum heavy ends. As shown for the case ofhydroxyaluminum, some additives stabilize clays by a combination of differenteffects. The same can be obtained with mixtures of clay stabilizers. Forexample, KCl/polymer systems are commonly used in drilling fluids. Someadditives combine clay stabilization with other properties. Potassium hydroxideslugs are known to improve well properties. Potassium hydroxide slugs are knownto improve well injectivity both by clay stabilization from the K+ ion and bydecreasing residual oil saturation caused by caustic flush. This paperinvestigates the stabilizing effect provided by high-molecular-weight polymeradsorption on montmorillonite clay dispersed in a sand matrix. All the polymersused in this investigation are either nonionic or anionic; thus, the onlyphenomenon involved is the coating of clay particles by adsorbed phenomenoninvolved is the coating of clay particles by adsorbed polymer molecules. Although their interaction with clay particles polymer molecules. Althoughtheir interaction with clay particles is weaker than that of cationic polymers, these polymers have several advantages, such as excellent compatibility withmost brines and good propagation properties through reservoir rocks because oftheir moderate adsorption level. Indeed, because of their strong adsorptiontendency, injectivity of high-molecular-weight cationic polymers may be ratherquestionable, especially in low-permeability reservoirs. Our study is dividedinto two parts. First, an experimental method that uses core flow tests isproposed to evaluate the stability of montmorillonite clay particles in contactwith NaCl or KCl brines, Then, the same core test procedure is used to checkthe stabilizing effect of three different polymers - a polyacrylamide, a CMC, and an XG - after they have been adsorbed polyacrylamide, a CMC, and an XG -after they have been adsorbed in the porous media in the presence of the sameNaCl or KCl brines. Experimental Brines. Two series of core tests were performed: one with KCl brines withconcentrations up to 30,000 ppm and one with NaCl brines with concentrations upto 100,000 ppm. All brines contained 400 ppm NaN3 as a bactericide and werefiltered through 0.22- m Millipore (TM) membranes. Polymer Solutions. The polymers tested were a CMC, an XG, and two Polymer Solutions. The polymers tested were a CMC, an XG, and two polyacrylamides, PAMand PAM . PAM was obtained by shear polyacrylamides, PAM and PAM . PAM wasobtained by shear degradation of PAM (solutions blended in an Ultraturax (TM)mixer at 10,000 rev/min for 2 hours at T=95 degrees F [35 degrees C]). CMC andthe PAM's were commercial products in a powder form; XG was a fermentationbroth containing 4 % to 7 % polymer. SPEPE P. 160
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
Summary Eleven hydraulic fracture treatments were performed in deep (3300 to 3800 m[10,830 to 12,470 ft]), extremely high temperature (180 to 195 C [356 to 383OF]), naturally fissured, gas-condensate reservoirs. Formation permeabilitiesat the fractured well locations range from 0.003 to 0.2 md, permeabilities atthe fractured well locations range from 0.003 to 0.2 md, while the initialformation pressure gradient is about 0.13 bar/m [0.57 psi/ft]. The producingfluid is high-gravity gas (0.83 to 1.15 to air) and psi/ft]. The producingfluid is high-gravity gas (0.83 to 1.15 to air) and contains up to 22% CO2 andup to 4% H2S. Job sizes have ranged from 300 to 2000 m3 [80,000 to 528,400 gal]of fluid and 50 to 600 Mg [110,130 to 1,321,590 Ibm] of high-strength proppant. This paper emphasizes the general approach to well completion and stimulationtreatment design, treatment execution, and evaluation. Interesting itemsinclude the engineering of the fracturing fluids to sustain their viscosity atthe extreme temperatures and to reduce leakoff in these highly fissuredformations. An outline of the reservoir description is also given. Posttreatment well production has been excellent in most cases. Well Pi'sincreased from 0.01 to 0.6 m3/d bar2 [0.0017 to 0.1 scf/D-psi] to 0.235 to 7.83m3/d bar2 [0.04 to 1.3 scf/D-psi2]. Treatment results suggest that leakoff canbe controlled with particulate agents, that delayed crosslinking is the onlyway to execute particulate agents, that delayed crosslinking is the only way toexecute these treatments, and that hydraulic fracturing can greatly improve theproduction from naturally fissured formations. Fracture design and theproduction from naturally fissured formations. Fracture design and thepredicted well production are compared with post-treatment performances inpredicted well production are compared with post-treatment performances inselected wells. Introduction After the successful execution and subsequent improved performance of amodest hydraulic fracture treatment in a high-temperature performance of amodest hydraulic fracture treatment in a high-temperature gas-condensate well, it became obvious that a much longer hydraulic fracture was indicated. Thisconclusion was based on the apparent reduction of reservoir permeability causedby the emergence of gas condensate and on the fact that a finite conductivityhydraulic fracture, producing in a fissured formation, exhibits an apparent(effective) length significantly smaller than the real length. Both reasonspoint to the necessity of performing large hydraulic fractures in suchformations. Massive hydraulic fracturing has proved to be the most successfultechnique to improve the productivity of tight gas sands. Deeply penetratingfractures can substantially improve well productivity and ultimate recovery tothe point where uneconomical wells productivity and ultimate recovery to thepoint where uneconomical wells can become profitable. Many works haveillustrated the merits of obtaining long, highly conductive fractures inlow-permeability reservoirs. However, most of these publications deal withmoderate temperature, homogeneous, and (probably) isotropic sandstoneformations. Except for geothermal wells, few high-temperature >180deg.C[>356deg.F]) case histories of hydraulic fractures have been discussed. Thewell-known constant-height, ideal-fracture-geometry models, which assumehomogeneous, isotropic media, may not be applicable in anisotropic, naturallyfissured reservoirs. Other models could be more appropriate in such asituation, as indicated by the analysis of abnormal treating pressures observedduring hydraulic fracture treatments. Some published case studies of fracturingin highly anisotropic formations show not only difficulties with the executionof hydraulic fracturing, but also poor improvement of well productivity. Withthat in mind, we designed and performed Il hydraulic fracture treatments indeep [3300 to 3800 m [10,830 to 12,470 ft]), extremely high-temperature (180 to195deg.C 1356 to 383deg.F]), naturally fissured, gas-condensate reservoirs. Anoverview of these treatments suggests certain answers to questions posed in theliterature. Treatment Considerations The treatments were done in specific formations of three differentreservoirs: Molve, Kalinovac, and Stari Gradac. These reservoirs are located innorth Croatia, close to the Hungarian border, and constitute the main part ofthe Drava depression of the Pannonian basin (Fig. i). Geological and physicalproperties of the Kalinovac field are described in Refs. 1 and 18, while Ref.19 gives a more complete geologic description of the Drava depression. In thisstudy, the reservoir rocks were represented by the following.Devoniancarbonate schists of pronounced fracture porosity and permeability. lower Triassic quarizites/metarenites with distinct microfractures and vuggyporosities. Middle Triassic, early diagenetic, extraordinarily anisotropicdolomites (with almost vertical fractures) from the Molve and Kalinovac fields, and coarse clastic rocks from reservoir formations at the Stari Gradac field. Lower Jurassic, late diagenetic, molitic dolomite from the Molve field only. Miocene carbonate facies (grainstone, wackstone, packstone-typelithotharnian limestone) only from the Molve field. The packstone-typelithotharnian limestone) only from the Molve field. The Kalinovac field, whichis of the same age, is represented by clastic rocks of low flow capacities. Thesame clastic rocks contain no hydrocarbons at the Stari Gradac field. Triassicand Jurassic dolomites have strongly pronounced anisotropic properties. Theyare characterized by an exceptional number of fractures of thesouth-southwestern slope and strike parallel to the main tectonic lines.parallel to the main tectonic lines. In such reservoirs, hydraulic fracturingmay not be successful. Regardless of the origin and geological history of thefissures and natural fractures, the current state of stresses influences theirdisribution and orientation. Because stresses are compressive in nature, themaximum stress would preferentially close fissures normal to its direction. This would result in a permeability anisotropy with a maximum value in thedirection of maximum stress. This configuration is the least favorable forexpected production increase from the hydraulic fracture. Furthermore, the hopeof connecting natural fractures, which generally follow the general trend ofthe manmade fracture, may not be realized to any appreciable degree. Anyintersection of natural fractures by the hydraulic fracture, however, createsunique problems during execution because of the presence of discontinuitiesthat may affect the propagation path of presence of discontinuities that mayaffect the propagation path of the induced fracture and high leakoff caused bythief fissures. Warpinski and Teufel considered the effect of geologicaldiscontinuities on the propagation of a hydraulic fracture, giving criteria forthe fracture to alter its direction. if treating pressures are large enough, shear slippage may be induced along joint or fissure sets. Jeffrey et al. analyzed the condition for effective proppant transport in those situations. When proppant bridging is present, the resulting increase in treating pressuresmay iced to dendritic fracturing. Kiel discussed the advantages of the createdconnected pattern, which results in volume drainage vs. the classic arealdrainage created by a planar fracture.
- North America > United States > Texas (1.00)
- Europe > Croatia > Virovitica-Podravina County (1.00)
- Europe > Croatia > Osijek-Baranja County (1.00)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.45)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.44)
- Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.99)
- Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Kalinovac Field (0.99)
- Europe > Croatia > Pannonian Basin > Stari Gradac Field (0.99)
- (6 more...)