Post treatment fracture flowback procedures during closure are often critical to the retention of fracture conductivity near the wellbore. Postfrac production performance largely depends on this conductivity. The importance of proper flowback procedure has been documented in the fracture industry, but definitive guidelines for flowback design have never been established. As a result, many misconceptions exist regarding the physics of proppant flowback and its effects on the final proppant distribution in the fracture.
This paper presents a rigorous study of fracture flowback and proppant migration during closure using a fully three-dimensional fracture geometry simulator (GOHFER). The effects of rate of flowback, location of the perforation interval, final proppant concentration, and the fracture geometry prior to flowback on the retained post closure proppant concentration are discussed. Consideration is given to the fluid velocity field in the created fracture resulting from the flowback, and its effects on proppant movement and localized fracture closure. These studies illustrate the difference between "forced closure" and "reverse screenout" concepts in flowback design. Other effects such as crossflow between multiple perforated layers are also studied. Simulation studies indicate that selection of a desirable flowback rate is very sensitive to crossflow effects resulting from induced fractures in multiple stress layers. This crossflow can result in significant overflushing of proppant in the lower stress zones, if not countered by properly applied flowback procedures. Very high flowback rates, exceeding the total leakoff rate, may be needed to avoid such overflushing.
The results of this study are assimilated into a set of recommendations for optimum flowback design leading to the maximization of the near-wellbore fracture conductivity and maximum attainable conductive length in communication with the perforations. Ideally, any properly applied controlled flowback procedure should induce a reverse screenout at the wellbore - forcing closure on the proppant by packing the near-wellbore area, not by depleting fluid pressure and "pinching" the fracture closed.
Postfracture flowback procedure is known to be very critical to the production performance of a fractured well. It is particularly so in tight formations. Experience shows that improper flowback procedures often lead to poor retained conductivity near the wellbore due to proppant movement into the wellbore or proppant crushing at or near the wellbore. Robinson et al. discussed the merits of flowing back wells on a small choke to minimize the closure stress on the proppant resulting in crushing. These authors also recommended initiation of low rate early flowback of the fracture fluid, in case of excessive closure time common in low permeability formations. Longer closure time allows proppant to settle in the open fracture due to breaking of the cross-linked polymer gel or rheological deterioration of foamed fluids. This may severely reduce proppant pack conductivity at or near the wellbore. An early induced closure, suggested by Robinson et al., should lock the proppant pack between the fracture walls before much settling can occur Subsequent studies by Ely, et al. showed that such a forced closure technique, coupled with high proppant concentrations and appropriate fluid quality control, significantly improves the productivity of low permeability oil and gas wells. Ely, et al. also recommend a forced closure implementation procedure within thirty seconds of completing flush. They suggest less than 10-15 gallons per minute flowback rate up to 30 minutes after near wellbore fracture closure is detected from surface pressure measurements.
The Alkaline-Surfactant-Polymer, ASP, process can significantly enhance waterfloods for appropriate reservoirs using carefully designed, reservoir specific, chemical injection strategies. This ASP technology recovers waterflood residual oil by reducing the capillary forces trapping the oil and improving the overall contact efficiency. The Minnelusa formation in the Powder River Basin was the location of the first field-wide application of this process in the U.S. An assessment of this early project nearing the end of its economic life and of other ongoing ASP projects provides an estimate of the potential of the ASP process to add reserves in other Minnelusa fields.
Analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the total original stock tank oil in place exceeds one billion barrels. The potential incremental oil recovery of the ASP process to these fields approaches 130 million barrels. This process can be applied at an incremental cost of $1.60 - $3.50/bbl.
An Alkaline-Surfactant-Polymer, ASP, design was developed and applied to the West Kiehl Minnelusa Field beginning in 1987. This was the first field-wide application of the ASP process in the U.S., but was applied as a secondary recovery method following primary production. This made the interpretation of the waterflood incremental oil somewhat more speculative, as there was no bases for establishing waterflood recovery by decline analysis. A complication was the field size, configuration and number of wells meant that a significant fraction of the pore volume could not be swept by flooding processes. The first published analysis in 1992 showed an incremental recovery of 0.11 pore volume (340.5 Mbbl) based on project performance and laboratory data. A much more detailed evaluation was performed relying on new laboratory data, numerical simulation, and much more field performance data to assess the effectiveness of the ASP process, and to compare the West Kiehl performance with that of other Minnelusa fields. This paper is a summary of the findings of the detailed evaluation.
Seismic data in which anisotropy is observed have been used to detect and characterize the natural fractures, in the Bluebell-Altamont, Utah, field. We show an (azimuth-dependent) amplitude variation with offset (AVO) anomaly in the P-wave reflection seismic, attributable to the gas-filled vertical oriented fractures, and substantiated by the 9-component VSP.
The detection of gas-filled natural fractures ahead of the bit is desirable for making a producing well in many low permeability formations in the Rocky Mountain basins. The Dept. of Energy has funded a study to demonstrate the use of multi-component seismic to detect high fracture density zones and predict fracture orientation ahead of the bit. Multi-component means that both P wave and shear-wave seismic data are examined. We have acquired two crossing lines of 9-component reflection seismic and two 9-C VSPs (vertical seismic profiles) to characterize the seismic anisotropy in the Bluebell-Altamont field study area (Figs. 1 and 2). By anisotropy, we mean that the value of the property measured depends upon the azimuth (direction) in which the measurement is made. Nine-component means that three sources (P, and two shear wave) and three receiver types (vertical and two horizontal) were used in acquisition. We include four pieces of information as necessary in this study: 1) the seismic anisotropy; 2) the geology, fractures, stratigraphy, and structural setting; 3) the in-situ stress field orientation (today); 4) the preferred flow direction within the reservoir (the maximum horizontal permeability direction).
Core and wireline data are used to describe the lithology and the natural fractures. The in-situ stress field orientation comes from the orientation of the nearby gilsonite dikes and from borehole ellipticity studies. The preferred flow-direction within the reservoir is under current study, The seismic an isotropy will be discussed in this paper.
The Uinta Basin of northeast Utah is an asymmetric east-west trending basin with a steep north flank bounded by a thrust, and a gently sloping (1-2 degree) south flank. Bluebell-Altamont field is located along the basin axis and north-central portion of the basin in Duchesne and Uintah counties (Fig. 1) Production is mainly from numerous sandstone and carbonates in the Tertiary Wasatch, lower Green River and upper Green River formations.
The Frontier Formation of the Moxa Arch in southwestern Wyoming provides an excellent example of the interplay among sedimentation, diagenesis, and tectonics on reservoir quality and performance. During the Cretaceous, thrust uplift and crustal loading occurred in the Sevier Orogenic Belt to the west of the foreland basin. The thrust sheets provided ample sediment to the Moxa Arch area during Frontier time. These sediments accumulated in wave-dominated deltaic, strandplain, coastalplain, and incised valley-fill depositional environments. The tectonic activity in the Sevier Orogenic Belt caused recurrent differential movement of orthogonally-shaped basement blocks along the Moxa Arch. These Movements created fractured lineaments at block boundaries. In addition, the recurrent movements of basement blocks influenced paleostructuring, diagenetic fluid migration paths, and sediment dispersal patterns of the Frontier.
The depositional facies of Frontier sediments control the primary porosity and permeability trends of Frontier reservoirs along the Moxa Arch. Post-depositional fractures caused by recurrent differential movements along zones of weakness at basement block boundaries secondarily enhance permeability and performance characteristics of Frontier reservoirs. Both the depositional facies and post-depositional fracturing of the Frontier influence the diagenetic trends affecting secondary porosity and permeability characteristics of Frontier reservoirs along the Moxa Arch. It is this complicated interplay of depositional, tectonic, and diagenetic influences that control the characteristics of Frontier reservoirs along the Moxa Arch.
The Frontier Formation in the Green River Basin (Figures No. 1 and 2) is a stratigraphically complex exploration target. There are multiple stacked reservoirs that reflect the interplay among variations in sediment supply, fluctuations in eustatic sea level, tectonism (contemporaneous and post-depositional), and diagenesis. Since the l920's, more than 1.45 TCF of gas has been produced from reservoirs in the Frontier Formation of the Green River Basin. Estimated ultimate recovery from more than 1540 producing Frontier wells is almost 2 TCF of gas. Most of this gas occurs in stratigraphic traps.
The objective of this paper is to quantify the distribution of potential flow units within valley-fill outcrop deposits by utilizing geostatistical parameters, especially variograms. The Newcastle (Muddy) Sandstone , which is a prolific producer in the Powder River Basin of Wyoming, is the subject of our outcrop reservoir characterization analysis which compares the relationships of detailed geological (sedimentological) interpretations of facies, detailed in situ permeability measurements, and outcrop gamma-ray log surveys. Much of the Newcastle (Muddy) Sandstone, which crops out near Newcastle, Wyoming was deposited by tidal currents backfilling valleys formed during a Lower Cretaceous sea level drop. The Skull Creek Shales which underlies and is lateral to the Newcastle sandstone forms lateral and bottom seals.
We concurrently measured the permeabilities and gamma-ray responses of beds on three vertical transects with a grid extending normal to the bedding and three lateral grids which are as nearly parallel to the bedding as possible. We generated geostatistical parameters from these data sets. In all cases, Dykstra-Parsons coefficients are in the neighborhood of 0.35 for the single-unit data and above 0.8 for the multi-unit measurements. Coefficients of variation are below 0.5 for single units and above 0.8 for multi-unit data sets.
Multi-unit variograms show hole effect and often strong trend, while single unit variograms always indicate nugget effect with a weak trend. The correlation between the plots generated from measured permeability and gamma-ray responses are impressive. Permeability and gamma-ray variograms are similar. The variograms in the vertical and horizontal directions are quite different. Therefore, they cannot substitute one for another. We also concluded that relative semivariograms are a better way of Presenting formation heterogeneities. We observed that abrupt variations in outcrop gamma-ray values are also excellent indicators of bed contacts.
We used the generated geostatistical parameters in a simulated annealing program to predict permeabilities of lateral profile A, and concluded that variogram, mean and standard deviation are required but not sufficient parameters to predict the distribution of reservoir heterogeneity.
Reservoir characterization seeks to identify reservoir compartments that manifest distinct properties in permeability, porosity, thickness, saturation etc.. Detailed description of reservoir compartments is a critical step in planning for performance predictions required for future investments. In numerous cases the completion, infill drilling, stimulation, and improved recovery operations were inefficient because of the lack of knowledge on reservoir heterogeneity, and the fact that the improved recovery processes are very sensitive to inherent uncertainties in the distribution of heterogeneities.
Heterogeneity is a widespread feature in all naturally-occurring permeable media and one of the most important factors governing fluid flow. Reservoir heterogeneity, which is determined by variations in permeability, porosity, thickness, saturation, faults and fractures, and different facies/rock characteristics, is primarily the result of complex geologic processes that vary in time and space.
An outcrop study is a useful tool for reservoir characterization because it allows analysis of the continuity of formations in three dimensions, and investigation of in-situ vertical and horizontal variations in properties on an inter-well scale. A reservoir characterization study of outcrop formations allows closely spaced lateral and vertical sampling which is necessary for the detailed rock description component of reservoir characterization. This detail can be used in planning advanced production processes applied to analogous subsurface reservoirs.
The findings of any outcrop study should be checked for their applicability before it is applied to subsurface formations.
In the last several years, limited-entry perforating has been used for hydraulically fracturing the Codell and Niobrara formations in the Denver-Julesburg (DJ) Basin. Limited-entry perforating reduces stimulation costs with no apparent effect on production.
Several papers have presented guidelines for designing a limited-entry treatment. A primary concern for treating multiple intervals is to ensure that both zones receive the necessary treatment. Currently, some operators simply ratio the number of perforations in each interval to the volume of treatment required for each interval. To ensure that both zones are being treated, a minimum pressure drop of 700 to 1,000 psi is usually used for limited-entry design. Changes in the perforation discharge coefficient and diameter during the treatment, combined with changes in the net treating pressure, affect the perforation pressure drop calculation. To determine the actual pressure drop across the perforations, designers use a real-time spreadsheet calculation.
This paper reviews limited-entry treatments pumped in 34 wells that verify spreadsheet calculations. Changes in the perforation discharge coefficient and diameter will be presented, as well as the effect of proppant concentration and velocity through the perforation. The current spreadsheet calculation used on location to calculate the pressure drop across the perforations is also discussed.
The Niobrara and Codell formations are the two primary production intervals for most of the wells being completed in the DJ Basin. The Niobrara is a micritic limestone consisting of three benches. At a depth of approximately 6,800 ft, the overall interval is generally between 150 and 250 ft thick. The Ft. Hays formation, the lower member of the Niobrara group, separates the Niobrara and Codell. There is a transition at the top of the Codell from a carbonate to a calcareous sandstone to a fine-grained sandstone with a high clay content. At a depth of approximately 7,000 ft, the Codell is typically 8 to 14 ft thick. Both the Codell and Niobrara are overpressured gas reservoirs with a low permeability ranging from 0.01 to 0.1 md.
In the past, the Codell and Niobrara intervals were fractured separately.
Fracturing from horizontal and highly deviated wells can often result in complex, non-planar fracture geometry. A two-dimensional model was developed to analyze the effects of non-planar fracture propagation for different in situ boundary conditions and hydraulic fracturing parameters. Numerical simulations show that curving fracture geometry reduces created fracture length compared to a planar fracture and causes a fracture width restriction at the wellbore. Reduction in fracture length can reduce expected well stimulation effects and jeopardize well economics. Near-wellbore width restrictions increase fracture treating pressure and may cause wellbore screen-out during the proppant stages of a fracturing treatment. The negative impact of non-planar geometry can be mitigated with short perforated intervals, high viscosity fracturing fluids, proper wellbore alignment and pre-pad proppant slugs for near-wellbore erosion.
Hydraulic fracturing in deviated and horizontal wells offers new challenges compared to operations in vertical wells. The fracture geometry can be more complicated due to the fact that the wellbore is not necessarily aligned favorably with the in-situ stress state. Non-planar propagation of the fracture can result in excess treating pressure, potential bridging and screen-out of the proppant near the wellbore, and high closure stresses on the proppant. Experimental work has shown that for non-planar fracture geometries, fracture widths near the injection point are diminished and treating pressures are abnormally high.
The numerical model developed for this work is intended to quantify the effects of non-planar fracture geometry on treating pressure, fracture width, fracture length, and potential sand transport. It can be used as a predictive tool to analyze the effects of in-situ stress magnitudes, wellbore orientation, perforation interval length, pump rate and fluid viscosity on fracture treatment behavior for highly deviated and horizontal wells.
The Morrow formation in Hutchison County, Texas was long considered incapable of producing hydrocarbons at an economic rate. Most post-frac production rates were the same or less than pre-frac rates. Only high flow rate, non-stimulated completions were considered economic, but these completions were few in number. These facts lowered expectations for sufficient recovery of investment necessary to continue developmental drilling.
Utilization of modern fracture model techniques, core analysis, fluid testing and stress data lead to a system of stimulation techniques, fluids and proppants that has created a cost-effective stimulation system for the Morrow formation. Lithology studies showed that the frac fluid was primarily critical to success. These studies lead to an unorthodox fluid. It contained two elements that would not be considered practical in any other formations or circumstances in the Western Anadarko basin. Proppant placement was identified as the second most important issue. Fracture height was found to be controlled by permeability, not stress. This led to the discovery that proppant convection did not allow for good proppant placement. Proppant staging methods were augmented to combat excessive convection and then acquire advantageous proppant placement. Proppant selection was identified as the third most important criteria. Reservoir stresses and modeling showed that high cost, high stress proppants were not necessary. Lower cost, larger sized proppants yielded much higher conductivity than in previous completions.
These criteria were integrated into a solution which brought the post-frac production rate from a one fold to a ten fold increase.
The West Arrington Morrow field of Hutchison County, Texas contains many producing horizons. One of which is the Morrow sandstone. This zone has been long overlooked for it's potential in supplying hydrocarbons due to problems in completions. Fortunately for Arrington CJM, Inc., their first three experiences with the zone were high flow rate, natural completions. Unfortunately, this was not the standard for completions to come.
Z. Rahim, S.A. Holditch and B.M. Davidson
During 1992-93, Davidson et al. conducted intense quality control (IQC) operations on 54 hydraulic fracture treatments. Their number one conclusion was that "Modern fracture fluid systems are very complex with viscous properties that are not fully understood". Even though a variety of problems can occur in the field, the most common and most serious problems were usually with the crosslinker and/or the breaker systems. If the gel is overcrosslinked or undercrosslinked, the fluid viscosity decreases, and the created fracture dimensions and proppant transport characteristics are adversely affected. If too much breaker is added, the fluid viscosity decreases, once again adversely affecting both the created fracture dimensions and proppant transport. If too little breaker is added, the fluid may never break or may never clean up. This can significantly reduce the productivity or injectivity of the well.
The statistics generated by Davidson et al. indicated that serious problems occurred with crosslinked, water based fracture fluid systems 78% of the time. This is consistent with previous quality control work performed in the industry by others. These authors stated that fluid problems occurred in 70-80% of fracture treatments. If IQC operations are applied, these serious problems can be discovered and corrected prior to pumping the fracture treatment.
The IQC operations are performed in the field using special equipment to test the actual fluids and chemicals that will be used during the fracture treatment.4 We have found that to properly test the chemicals, such as buffers, crosslinkers, and breakers, the tests must be conducted at an elevated temperature that represents formation temperature. To ensure that the results are meaningful, one must mix the gels correctly and test them under conditions that simulate mixing, shearing, and temperature changes in the actual field application. The equipment and manpower required to perform IQC tests in the field typically can cost between $5,000 and $15,000 per treatment.
To obtain approval by management to conduct IQC tests, one must determine that the economic benefits of conducting lQC are substantially more than the costs. The Gas Research Institute (GRI) has funded detailed studies to compute the benefit-to-cost ratios for applying new technologies, including IQC operations. In the GRI work, it was concluded that under certain conditions, IQC can be very beneficial and can provide a substantial return-on-investment to the operator.
To further illustrate the benefits, we have thoroughly reviewed the field data collected by Davidson et al, and have used their results to construct examples illustrating how IQC can affect the ultimate recovery and economics from typical gas wells. The information in the paper by Davidson et al. clearly showed how the fracture fluid properties are affected by the chemicals and how they are mixed. In this paper, we want to illustrate how these variations n fluid properties actually affect the fracture dimensions, gas flow rates vs time, and the economics of producing low permeability wells that require fracture treatments to produce under optimal conditions.
The prediction of hydraulic fracture growth is controlled in part by the subsurface confining stress. Previous work has been based upon a simple relationship between vertical overburden stress and horizontal stress as a function of Poisson's ratio. Field measurements of closure stress have failed to consistently verify the relationship between vertical and horizontal stress, so that additional calibrations are required. Alternatively, consideration of an anisotropic Poisson's ratio results in a different relationship between vertical and horizontal stress. A portion of the observed difference between theoretical and calculated closure stresses is probably due to such an anisotropic effect. The azimuthal direction of induced hydraulic fracture growth is controlled by anisotropy in both tensile strength and Poisson's ratio. Field measurements of closure stress do not necessarily determine the minimum horizontal stress in anisotropic rocks. Geophysical measurements of anisotropy can greatly affect the engineering of hydraulic fracture treatments.
In exploration for additional oil and gas reserves, hydraulic fracturing is performed routinely to stimulate production. Conceptually, hydraulic fracturing is the process of pumping fluids into a well fast enough and at sufficient pressure to fracture the rock and create a conductive conduit between formation and wellbore. There is a wealth of literature indicating the importance of hydraulic fracturing in petroleum engineering. In fact, for most tight gas sand field developments, the dollar investment spent in hydraulic fracturing is a close second to drilling expenses. The need to better understand the physical processes involved in hydraulic fracturing cannot be over-emphasized.
Most previous research on hydraulic fracturing is focused on fluids, additives, and pumping during the fracturing operation. Relatively little work has been done on the actual physical processes controlling the growth of hydraulic fractures in the subsurface. Howard and Fast (1970) published a well known summary of hydraulic fracturing.