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Restimulation of wells completed in the Codell formation, a tight gas sand, has proven to be successful in the Wattenberg Field in Colorado. Beginning in 1997, Codell refracturing evolved into a massive program involving hundreds of wells per year. To date, HS Resources has restimulated over 750 Codell wells, increasing reserves and resulting in a project ROR of 100% with finding costs below $4.23 per barrel oil equivalent. This is a case study of the program conducted by HS Resources.
This paper summarizes the refrac program, and its evolution, since its inception. The candidate selection process is examined, as well as geological and operational considerations when restimulating old wells. The evolution of stimulation treatments and fluids are also investigated. The use of 3D fracture simulations, run in real-time during the refracture treatments, and their results are discussed. Finally, both economic and production results are presented.
Fracture treatment fluids and designs have varied greatly since the full-scale development of the Codell zone in the Wattenberg Field of northeast Colorado (Figure 1) began in 1981. Initially, small sand volumes and a variety of fluids were used to complete the Codell zone. With the improvement of frac fluids and placement techniques in the 90's, frac treatment designs changed dramatically towards larger sand concentrations and higher pump rates. Furthermore, with the trend towards completing the Niobrara in addition to the Codell, cost cutting techniques such as limited entry completions were employed. This technique controls the anticipated placement of the frac treatment by the number of perforations shot across each interval. In many of these wells, there are only 4 to 6 perforations in the Codell zone, which has been shown to be the most prolific reservoir of the two in most areas of the field. Varying degrees of effectiveness have been demonstrated by the historical evolution of frac design and placement. Current fracture modeling has shown that the techniques discussed above can limit the induced fracture lengths in the Codell, and thereby, negatively affect the production performance of the well. Operators in the Denver-Julesburg (D-J) Basin discovered, as early as 1989, that restimulating wells with small or ineffective original treatments yielded impressive and sometimes dramatic results. In June 1997, HS Resources began their refrac program.
In the Wattenberg Field, the Codell Sandstone (Figure 2) is a highly bioturbated marine bar-margin deposit, flanking a central bar facies to the south. Moderately low depositional energies and considerable authigenic alteration of feldspar and rock fragment grains have sourced clay contents as high as 30% in some portions of the field. These interstitial clays exhibit grain-coating, pore-lining and pore-occluding habitats, often reducing permeabilities below 0.1 md, although porosities range from 10 to 25%. As a result, hydraulic stimulation is used to establish high permeability fairways (hydraulic fractures) that connect larger cross sections of low permeability matrix and micro-fracture networks to the wellbore.
Regionally, the Codell Sandstone in the central portions of Wattenberg Field contains unique reservoir characteristics and is bounded by multiple trapping factors. Reservoir pinchouts to the south, southeast and northeast of Wattenberg, regional basement faulting to the west and north and corresponding porosity and permeability reductions toward these features help create an effective regional oil and gas trap within the Codell in the central field area. Correspondingly, the central field area contains the greatest maximum porosity and permeability reservoir in the Codell play, with the highest GOR's, exceeding 15,000 scf/bbl. All of these factors mutually overlap to create an overpressured cell in the Codell reservoir in the central field area (Twps. 3 to 5N, Rgs. 65 to 66W). Pressure gradients range from about 0.445 psi/ft, on the flanks of the field, to a maximum of 0.669 psi/ft in the center of the overpressured cell.
Abstract This paper reports on a study conducted to measure the orientation of fractures created during initial fracture and refracture treatments in the Codell formation of the Wattenberg Field, Colorado. The Codell is a thin, low permeability sandstone that is laterally continuous across the field area. Due to the low permeability, stimulation is required for economic development of the Codell. Refracturing of Codell wells in Wattenberg Field has been successfully performed for the last decade and several reasons have been suggested for the success of Codell refracs including reorientation of fractures. Surface tiltmeter mapping was performed during this study on several initial fracture and refracture treatments in the field to determine fracture orientation. The average azimuth of initial fracture treatments was N66°E. Significant reorientation occurred on some refrac wells and the average azimuth of refracture treatments was N29°E although highly variable. It has been observed that fracture orientation can vary due to changes in pore pressure as the result of asymmetrical depletion and/or injection or due to structural features. In this case we believe that asymmetrical depletion is affecting the in-situ stress orientation and thus the fracture orientation. There were also indications of fracture complexity with some treatments showing a change in fracture orientation during the treatment and several showing higher than normal horizontal components. The results from this study help explain the success of refracture treatments in the Codell. Refracture reorientation allows existing wells to contact new reservoir increasing gas recovery per well. There may be the potential to fracture wells for a third time (re-refracs) for additional fracture Energy; Greg McIntosh, Anadarko Petroleum; and reorientation and improved gas recovery. Mapping and production results are discussed in this paper. Background The objective of surface tiltmeter mapping on this project was to determine the fracture orientation of initial fracture treatments and refracture treatments of the Codell formation in the Wattenberg Field. The primary focus of the project was to determine if refracture reorientation was playing a role in the restimulation success in the Codell. Refracture reorientation allows an existing well to contact new reservoir and improve ultimate recovery. The secondary objective was to determine fracture orientation in the J-Sand, a target zone below the Codell, in order to optimize well locations. A mix of fracture treatments was monitored during the project, initial treatments in both the Codell and J-Sand and refrac treatments in the Codell, in order to determine original fracture azimuth and refracture azimuth. Codell Formation The Wattenberg Field is located in the Denver-Julesburg (DJ) Basin as shown in Figure 1. The producing area is a multiple pay accumulation in a basin center which is associated with a geothermal anomaly. Productive zones within the field include the J (Muddy), Codell, Terry (Sussex) and Hygiene (Shannon) sandstones and the Niobrara chalks and shales as shown in Figure 1.
Refracturing wells, completed in the Codell formation, has caused a resurrection in activity in the Wattenberg Field of the Denver-Juleseburg (D-J) Basin. HS Resources (HSR) has increased average oil and gas rates by greater than 500% by restimulating over 750 Codell wells. The evolution of applied fracturing fluid technology has played a major role in the success of the Codell refrac program.
This paper will identify and evaluate the benefits to well performance and economics gained from the evolution of fluids used in the Codell refracture program. In this effect, the fluid systems will be compared using treating pressure characteristics, production analysis, fluid properties, and rheological property evaluation via specialized testing apparatus and economic results.
The Codell Sandstone is Upper Cretaceous in age and produces condensate and gas with little water at true vertical depths of 7,000 to 8,000 feet. The Codell is a highly bioturbated marine bar-margin sandstone deposit which was initially over pressured (0.6 psi/ft pore pressure gradient, in the central portion of the field). Bottomhole static temperature ranges from 240 to 260°F across the field with 250°F as the expected average. The Codell is 10 to 20 feet thick and is rich in clay (15 to 25% by volume). Sediment sorting is poor with mixed layer illite/smectite clay occupying pore filling and pore-lining habitats. Trapping is enhanced by regional basement fault trends to the west and north, and an erosional pinchout to the south, southeast and northeast.
Pore volume (porosity x thickness) patterns parallel the erosional edge of the Codell to the southeast of the Wattenberg field. Typical pore volume phi-h values range from 1.5 to greater than 2.0. Pore volume is only important if the value falls below the 1.5 value as exists in the unproductive southeast area of the Wattenberg Field.
The permeability in the Codell interval is very low due to the small and tortuous pore network1. Typically, mercury injection into the core shows that 94% of the rock pores has a radius of one micron or less. Numerous interpretations of post frac permeability have showed the effective permeability ranging from 0.01 to 0.09 md.
Evolution Towards Refracturing
Early activity in the basin consisted mainly of drilling to, and exploiting, the J-Sand formation. The Codell was only completed sporadically until the early 1990's. At that time, the Codell and Niobrara zones were typically completed together in a limited entry treatment2. The primary reason for commingled zone treatment was the favorable economics. Two other treatment styles were also investigated and performed by a variety of operators in the basin: Codell only completions and dual completions in the Codell and Niobrara.
From the extensive analysis of the three types of completions pumped on the Codell and Niobrara it was determined that:
Dual completions in the Codell and Niobrara correlated with higher well productivity.
Production from the limited entry treatments was 5 to 6% lower than the dual completion treatments.
Production from the Codell only stimulations was 20 to 21% lower than the dual completions.
Abstract Since 1998, over 4000 wells completed in the low-permeability Codell formation of the 300,000 acre Wattenberg Field in northeast Colorado have been remedially stimulated with massive hydraulic fracturing treatments. This remedial program has been extremely successful. A majority of the refracturing treatments in this study have yielded higher oil and gas rates than experienced following the original treatment, performed many years previously. Fluid and proppant volumes of the remedial treatments have been very similar, but certain characteristics of the fracturing fluid correlate significantly with variability in well productivity. The main correlating parameter has been the fracturing-fluid viscosity profile (FVP), which is defined by the early-time rate of viscosity buildup, the peak viscosity developed, and the rate of viscosity degradation following the peak. For each treatment, the FVP has been evaluated with a HTHP (high temperature/ high-pressure) rheometer, using a shear and thermal history representative of the Codell treatments. Within the Wattenberg Field, there is evidence that FVP has a multi-faceted impact on well productivity that is more than just being able to place the proppant into the formation. Introduction For this paper, we have studied more than 1,000 Codell wells, all treated with the same type of fracturing fluid (i.e., zirconium-crosslinked CMG.) Many changes have been made to the base fracturing fluid properties in an attempt to improve productivity, and although the Codell is a continuous, marine sandstone deposit, there are characteristics in the pay and bounding zones that warrant varying the fracture design for areas within the field. By recording the changing pre-job testing and job execution parameters, and correlating this data with the post-treatment well productivity, it has been possible to determine the most significant factor that effects well productivity. It was found that exceptional treatment results correlated strongly with the FVP. During the past year, there has been a significant improvement to well productivity resulting from a systematic modification of the FVP. Measuring Well Performance Since these wells are all restimulations, the prior well history has to be taken into account to compare well performance. This is done by utilizing a mathematical algorithm on each well that accounts for critical parameters such as cumulative and ultimate recovery factors, Gas-Oil-Ratio, original completion type, and performance of off-set wells. This algorithm establishes an expected performance for each well expressed in peak incremental BOE/month. The treatment results are then measured as the peak month incremental BOE which is the net gain in BOE/month. To then compare treatment performance between wells, the actual well performance is divided by the algorithm predicted performance and expressed as a percentage (i.e. >100% indicates outperforming the algorithm prediction). Figure 1 shows the results for the whole field expressed as actual/predicted results.
Abstract A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including: –Enlarged fracture geometry, enhancing reservoir contact –Improved pay coverage through increased fracture height in vertical wells –More thorough lateral coverage in horizontal wells or initiation of more transverse fractures –Increased fracture conductivity compared to initial frac –Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. –Increased conductivity in previously unpropped or inadequately propped portions of fracture –Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] –Use of more suitable fracturing fluids –Re-energizing or re-inflating natural fissures –Reorientation due to stress field alterations, leading to contact of "new" rock Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include: –Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids –Low pressured or fault-isolated wells with limited reserves –Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries –Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.