The current economic structure of the petroleum industry often requires multiple completions with production from each zone co-mingled to reduce completion costs. However, these multiple completions require a different approach to analyze the effectiveness of both the original completion and possible later stimulation treatments of low permeability formations. To reduce the financial impact of individual zone testing it is desirable to run production logs to detect the contribution from each zone to the total production rate.
Some wells encounter multiple low permeability pay zones that are uneconomical to complete and stimulate individually. If the well does not do as expected or has a problem producing, the problems may not be recognized by conventional testing. If multiple zones are stimulated simultaneously there may be a concern whether each zone was responding to the stimulation treatment. Radioactive isotopes are used as a tag during the stimulation process to measure completion and/or placement effectiveness. Other methods for evaluating stimulation treatments include well testing, using pressure drawdown, and/or buildup analysis. However conventional analysis' techniques are complicated to interpret with multiple completion intervals and may not yield information on the flow capacity of each zone.
With production logs it is possible to detect the type and rate of the fluids being produced from each individual zone in a timely manner. By comparing the open hole log analysis to a production log after stimulation it is possible to determine the effectiveness of the stimulation. This information could serve as a knowledge base for future stimulation design and improved well performance. Further computer analysis of the openhole logs, production logging data, and stimulation information could provide additional insight to enhance the economics of the reservoir development and to help understand wells that are producing below their expectations.
This paper will suggest guidelines for running production logs and show the usefulness of using these tools when evaluating multi-zone completions in tight gas sands. A three well example from the Rocky Mountain area is used to highlight the use of production logs to analyze multi-zone completions.
Current economic constraints in the petroleum industry have made cost-efficient, multi-zone completions frequently the practice of choice over traditional, single-zone completions.
Earlier numerical models for coal seam gas reservoirs assume that at initial reservoir conditions coal is either on or above the sorption isotherm, i.e., either equilibrium or saturated conditions prevail. Therefore, when undersaturated conditions exist, implementation of these models does not capture the physics of the problem accurately. In this paper, simple algorithmic procedures are proposed which allow the model to cross the isotherm between saturated and undersaturated regions during computations.
Several examples which demonstrate the successful application of the proposed algorithms are presented. Implementation of the switching mechanisms to existing coalbed simulators is straightforward and should significantly enhance their applications.
Coal seam gas, gas from devonian shales, geopressured aquifers and other unconventional gas reservoirs account for between 250 TCF to several thousands of TCF under a given set of economic conditions. Depending on gas prices, demand, tax incentives, or other circumstances, the actual figure can change. If demand is sufficient, interest in unconventional reservoir development will become even more widespread than it is today.
The majority of gas stored in coal exists in an adsorbed rather than free state. When the system is in equilibrium, the amount of gas adsorbed on the coal is governed by the sorption isotherm. A pressure drop in the cleat system (natural fracture network) causes gas to desorb from the micropore surfaces and to diffuse into the macropores. However, if the coal bed reservoir is undersaturated, substantial pressure drops must be achieved before any significant gas production is noticed. Figure 1-A is an example of gas production, and Figure 1-B represents water production from coal bed reservoirs which are initially at equilibrium and undersaturated conditions. Figure 1-C shows corresponding well block pressures for the two cases considered. While Figures 1-A, 1-B, and 1-C focus on the early time behavior, inserts in the figures show the responses of the reservoir over a much longer period of time.
The primary purpose of this paper is to present formulations that will capture the different behaviors exhibited by the coal bed reservoirs which are situated at equilibrium or saturated conditions and undersaturated conditions as displayed in Figure 1. There are two situations that need to be considered. First, the reservoir is initially in the undersaturated state, and as pressure decreases over the course of time, it enters the saturated condition. In this case, at the beginning of the simulation, the reservoir flow dynamics is described as single-phase flow of water with no gas desorption or diffusion. When pressures become sufficiently low, certain regions (starting within the immediate vicinity of the wellbore) cross the sorption isotherm.
The second situation involves a saturated reservoir which undergoes either a water or gas injection test. In either case, injection rates and coal properties will result in high pressures (especially near the wellbore), so that any existing free gas disappears. Consequently, the system crosses the equilibrium isotherm in the opposite direction, i.e., from saturated to undersaturated state.
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.
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.
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.
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.
Development of a retrograde condensate reservoir required accurate well productivity predictions for a capital commitment to gas processing facilities. Historically, Fussell identified that liquids condensing in the reservoir will result in a substantial productivity impairment. A single well model, which included a hydraulic fracture as part of the grid system, was developed to perform sensitivities for well test interpretation and to predict long term performance. Interesting results were obtained. The productivity of fractured wells was not impaired to the degree expected. Radial modelling confirmed the results obtained by Fussell. Current simulation technique allows for direct modelling of a hydraulic fracture instead of using an equivalent well bore radius. The distribution of pressure drawdown and condensate dropout around a hydraulic fracture results in limited productivity impairment. The methodology used and the results obtained are described.
This work was originally completed to forecast production from wells in a new field, which was being developed in the Deep Basin area of Alberta, Canada. The original study was comprised of geological characterization, PVT characterization, numerous well test sensitivities, as well as simulating the effects of condensate dropout on well productivity. The ultimate objective of this work was to make a nomination for a sour gas plant.
Due to space limitations, this paper represents an abbreviation of only the most important technical point: that for wells that are hydraulically fractured productivity is not as adversely affected by condensate precipitation as previously reported. This is with some regret on behalf of the authors who, as practising engineers, find the approach (or story) to be of as much interest as the actual result. In particular, about two thirds of the real work in this study was confirming formation permeability and fracture properties. To do this, interpretations from various disciplines of petroleum engineering, such as hydraulic fracture treatment monitoring, well test interpretation and core analysis, had to resolved. Justifying, explaining and communicating this input was a significant portion of the work on this project.
The paper has still been organized, as much as possible, to follow the historical development of the technical work. Material is presented under the following headings: Geological Description, PVT Characterization, Model Construction, Well Test Modelling, Effects of Condensate Dropout, and Conclusions. Originally this work was completed for a single well, which was later expanded to include other wells in other pools. Only the work done on the first well analyzed is presented, which does not apply universally to the area.
This paper discusses possible explanations, based upon previous studies, for the hypothesis that multiple fractures at the borehole wall may be a common feature of the hydraulic fracturing process. It then uses field examples to show how we concluded that a type of low-concentration screenout common to three fields in Texas and Oklahoma was caused by multiple fractures. Next, it shows how we developed a completion that controls loss of the pad and slurry to multiple fractures. Finally, it discusses some of the implications of our experience for completion design in general. Since the symptoms of the low-concentration Screenout have been documented in the literature by other authors and appear to be quite common, our design techniques should be effective in other areas as well.
The completion design combines unoriented, zero-degree-phased, big-hole perforations shot at low density; and small, high-concentration proppant slugs with clean spacer stages pumped very early in the treatment. These strategies were chosen (1) to limit the number of separate fractures that initiate from individual perforations, and (2) to screen out narrow fractures early in the treatment so that more width is developed in the remaining fracture(s). We have used these techniques to increase overall sand/fluid ratios (including the pad) from about 2.3 ppg (lbm added per gal fluid) to over 8 ppg, on modestly-sized treatments up to 200,000 lbm.
In all the areas covered by this study it had been difficult to complete stimulations when we tried to reduce pad fractions below 40% and/or increase sand concentrations past 6 ppg. The proppant-induced pressure increase that leads to a near-wellbore screenout (Barree) was a common factor in all these attempts. These screenouts occurred even when we had designed the pump schedules on modern, three-dimensional (3D) fracture design simulators, using reliable input data.
Even the most up-to-date simulators are notoriously unreliable design tools unless they are adjusted for the peculiar leakoff conditions of each well, either by a calibration treatment, or by a generous infusion of local knowledge. Uncalibrated simulations routinely predict ample width for slurry concentrations up to the operational limits of pumping equipment, but experienced engineers know that most treatments screen out at much lower concentrations. Unless fluid loss is increased by the modeler, or the screenout criterion is set very conservatively, design models do not predict fracture treatments should screen out at the low concentrations that they commonly do.
These results are puzzling when one considers just how little sand is contained in slurries that frequently cause screenouts. For example, Fig. 1 shows that a 6 ppg slurry contains only about 35% sand on a bulk volume basis and 18 ppg still has 25% excess fluid.