Katiyar, Amit (The Dow Chemical Company) | Patil, Pramod (The Dow Chemical Company) | Rohilla, Neeraj (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company) | Evans, Jay (MD America Energy LLC) | Bozeman, Tim (MD America Energy LLC) | Nguyen, Quoc (The University of Texas at Austin)
An immiscible hydrocarbon foam (HC-Foam) enhanced oil recovery (EOR) pilot has been designed and implemented in a hydraulically fractured tight reservoir in the Woodbine field, Texas. Although gas injection is being considered as the main EOR technology for unconventional tight fractured reservoirs, gaseous foams of this type have not been previously considered as an effective conformance solution. This paper presents experimental evaluation of the surfactant, field pilot design and implementation and performance analysis of the pilot towards developing an unconventional HC-Foam EOR conformance solution. Several surfactants were screened through a bulk foam test for the harsh reservoir conditions (120 ˚C, 3.23% salinity and ~27% clay). The selected surfactant was further evaluated for static adsorption on reservoir rocks at room temperature to ensure an economic field pilot. The surfactant was also evaluated for oil-brine emulsion tendency to mitigate any field implementation issues. A single horizontal injector and two surrounding horizontal producers pad was developed for an IOR/EOR pilot implementation in Woodbine field. Water and produced hydrocarbon gases were injected alternately as well as in co-injection mode, however no consistent incremental oil was observed. Injected gas and water broke through on the order of hours and days respectively. The injector showed more connectivity with one of the producers, suggesting a strong areal conformance problem. A steady baseline operation was established by co-injecting gas and water at a constant gas fraction and total constant rate that resulted in steady production baseline. The baseline injection was continued with surfactant injection in brine for in-situ foam generation. During five weeks of surfactant injection, foam generation and mobility reduction were confirmed with the increase in the measured bottom-hole pressure. Mobility control resulted in out of zone injection elimination for both gas and water and gas diversion to bypassed areas. With conformance corrected at the injector and deeper in the reservoir, oil production rates more than doubled, gas utilization was improved, and a low gas-to-oil ratio and improved volumetric sweep were confirmed. The increased oil production continued for at least 6 weeks after completing surfactant injection. More than 2000 bbl. of incremental oil was recovered in 11 weeks of pilot operation. Current work confirms the technical efficacy and potential of the gaseous foam conformance solution for incremental oil production in unconventional plays.
During development of the Eagle Ford unconventional resource near the San Marcos Arch, a non-productive mudstone associated with drilling issues was identified between the primary Eagle Ford producing zone and the underlying Buda Limestone. As the top of the Buda typically exhibits evidence of karsting but is unaltered when overlain by this mudstone, and the mudstone contains higher abundances of clay than the Eagle Ford, two questions were posed: (1) Does this mudstone represent a depositional system separate from the Eagle Ford and (2) does it act as a fracture barrier between the Eagle Ford and underlying water-bearing rocks?
The current study analyzed two cores from Lavaca and Fayette counties, which included petrographic, XRD, and geomechanical (point-load penetrometer and micro-rebound hammer) analyses to determine the mineralogy and geomechanical properties of the mudstone, the Eagle Ford, and the Buda. Logs from 345 wells within a six-county were used to correlate and map four horizons associated with the mudstone. These results were integrated with an earlier core study that included biostratigraphic, petrographic, XRD, and XRF analyses, and regional log correlations across the arch into the Brazos Basin.
The geomechanical tests found that the mudstone is significantly weaker than the overlying Eagle Ford, averaging 32% lower calculated unconfined compressive strength (UCS) values derived from the penetrometer and 36% lower using the micro-rebound hammer. Higher clay and lower calcite abundances within the mudstone are responsible for its lower strength; the XRD analyses found that the shale samples from the mudstone contained an average of 47% clay, whereas the Eagle Ford marls contained an average of 34% clay. The petrographic analyses found that the clay is concentrated in structureless layers that are interpreted to represent fluid-mud deposits associated with hypopycnal plumes.
The biostratigraphic study identified Early Cenomanian markers associated with the Maness Shale of East Texas which lies between the Woodbine and Buda, in agreement with the regional cross-sections which correlated the mudstone to the Maness. A hot gamma ray spike produced by a phosphatic lag at the top of the mudstone was key to the correlations. Thickness trends of the Maness differ considerably from the Eagle Ford; it has a distinct northeast-southwest trend and pinches out in southern Karnes County, suggesting that it was a depositional system unrelated to the Eagle Ford.
Comparison of Maness thicknesses with cumulative first year oil and water production data from over 2000 horizontal wells in the study area found a significant correlation between Maness thickness and water/oil ratios. In particular, there is a 50% decrease in water/oil ratios between Maness thicknesses of 5 to 10 ft, (1.5-3 m) suggesting that the Maness may be acting as a fracture barrier where it is >10 ft (3 m) thick.
The present study provides a comprehensive set of new analytical expressions to help understand and quantify well interference due to competition for flow space between the hydraulic fractures of parent and child wells. Determination of the optimum fracture spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Analytical and numerical model results are combined in our study to identify, analyze, and visualize the streamline patterns near hydraulic fractures, using physical parameters that control the flow process, such as matrix permeability, hydraulic fracture dimensions and assuming infinite fracture conductivity. The algorithms provided can quantify the effect of changes in fracture spacing on the production performance of both parent and child wells. All results are based on benchmarked analytical methods which allow for fast computation, making use of Excel-based spreadsheets and Matlab-coded scripts. Such practical tools can support petroleum engineers in the planning of field development operations. The theory is presented with examples of its practical application using field data from parent and child wells in the Eagle Ford shale (Brazos County, East Texas). Based on our improved understanding of the mechanism and intensity of production interference, the fracture spacing (this study) and inter-well spacing (companion study) of multifractured horizontal laterals can be optimized to effectively stimulate the reservoir volume to increase the overall recovery factor and improve the economic performance of unconventional oil and gas properties.
Albrecht, Tony (Geoscience, Hawkwood Energy, Denver, CO, United States) | Kerchner, Stacy (Engineering, Hawkwood Energy, Denver, CO, United States) | Brooks, Scott (Petrophysics, Hawkwood Energy, Denver, CO, United States) | Kolstad, Eric (Drilling, Hawkwood Energy, Denver, CO, United States) | Willms, Trevor (Engineering, Hawkwood Energy, Denver, CO, United States) | Klein, John (Geoscience, Hawkwood Energy, Denver, CO, United States) | Stemler, David (Geoscience, Hawkwood Energy, Denver, CO, United States)
The Mesozoic-aged Brazos Basin, situated at the southwestern-most extent of the East Texas Basin and along trend with the Maverick Basin, is bracketed by the Edwards Reef, San Marcos Arch and the Angelina Caldwell Flexure (
Recent studies have shown that the behavior of pure fluid in confinement deviates from its bulk state. This means that the vapor and liquid saturation curves, critical temperatures, pressures and densities of fluid in confinement are different from their well-documented bulk state values. While these single-component studies have been influential in our understanding of this peculiar phenomenon, the multi-component fluid phase behavior has yet to be investigated in depth. This is an important step, because production of liquids and natural gases from organic rich nanoporous shales involves fluids with a wide range of composition. Nanopore walls have significantly varying degrees of affinity to each component (selective adsorption). Consequently there will be large gradients across the pore width in not only density and pressure but also in concentration. This work is an investigation of phase changes of single and multi-component fluids in confinement with the help of molecular simulation. In the first part of this paper, phase diagrams of three single component (pure) fluids in confinement are constructed and studied. In the next part, a different methodology is utilized to construct phase diagrams of binary and ternary mixtures with light, intermediate and heavy hydrocarbon components. The methodologies are initially explained and verified by the bulk-state fluid behavior.
This study shows that the behavior of single component fluids approaches its bulk state at a confinement of approximately 13nm width. Furthermore, the impact of confinement appears to be greater on the vapor saturation curve than on the liquid curve. In the case of multi-component fluids, the phase diagrams seem to shift more severely with the increase of the percentage of light component in the mixture. Contrast in concentrations of the light and heavy components, amplifies the confinement effect. More specifically, confined multi-component fluids with high percentage of light components such as methane and ethane are expected to exhibit more dramatic changes in phase behavior. Lastly, critical temperature and pressures of confined mixtures obtained from our molecular simulations are compared to those obtained from other mixing rules and equations, such as Peng-Robinson equation of state, which are extensively used for fluid in bulk state. The differences in values obtained show the necessity for the development of new approaches for considering hydrocarbon fluids in confinement. The observations undermine the current practice of assuming bulk fluid parameters for fluid in shale plays.
Brooks, Scott (Hawkwood Energy LLC, Denver, CO) | Willms, Trevor (Hawkwood Energy LLC, Denver, CO) | Albrecht, Tony (Hawkwood Energy LLC, Denver, CO) | Reischman, Richard (Edgar Ignacio Velez Arteaga) | Walsh, John (Schlumberger, Houston, TX) | Bammi, Sachin (Schlumberger, Houston, TX)
Intrinsic anisotropy is known to exist in most organic shales due to their layered nature. Horizontal and vertical mechanical properties can sometimes be drastically different. Taking these differences into account can result in higher than expected pre-job calculated frac gradients. Often this type of information is based solely on experience gained from hydraulically fracturing other wells in a given area. Logging data obtained prior to stimulation can help predict these higher fracture gradients and can provide great value in the design of an optimized stimulation. This study documents the integration of log data obtained in a vertical pilot well and its associated lateral wellbore in the lower Eagle Ford formation in Robertson county, Texas. Acoustic data obtained from a dipole sonic that was run in the vertical pilot were correlated with data acquired from a new slim dipole array sonic tool that was conveyed through the drillstring in a lateral well and into open hole after it was drilled. Slowness measurements taken from the vertical and horizontal well data sets suggest that a high amount of intrinsic anisotropy was present. These predictions were confirmed by the post job stimulation data from the horizontal well. Combining the stress and petrophysical interpretations based on other log measurements provided reservoir and stimulation quality indicators that were then compared to actual production. Lessons learned were then implemented in later wells resulting in improved stimulation efficiency and production.
Managed Pressure Drilling (MPD) was successfully used to exploit the lower cretaceous Buda, Georgetown, Edwards, and Glen Rose formations in Houston and Madison Counties, Texas. The objective was to economically stimulate and commingle all of these zones. A comprehensive solution was developed to combat the principal causes of cost over-runs due to: 1) weak zones in the shallow formations above the productive intervals, 2) wellbore stability issues caused by sensitive shale formations, and 3) lost circulation caused by natural fractures in the productive interval. The operator was faced with several shallow low fracture gradient intervals above an extremely thick and sensitive shale sequence (Dexter Shale) above a 1,400' pay interval comprised of multiple fractured carbonate horizons. Moreover, the lowermost productive interval had a significantly higher pore pressure and the potential for significant gas deliverability while the shallower productive horizons had a lesser pore pressure and were primarily oil productive zones with associated gas. Problems encountered included excessive shale production, wellbore collapse, BHA sticking, and severe lost circulation. The operator drilled multiple wells overbalanced with various water based mud systems (conventional approach), in certain parts of the field. Success with water-based mud required a great deal of finesse and the operator was unable to achieve consistent, predictable results in the most prolific producing areas. Unexpected cost over-runs occurred and several wellbores were lost and required re-drilling.
Managed Pressure Drilling (MPD) allowed the operator to use Oil Based Mud (OBM) to control the sensitive shale formations while drilling with a mud weight low enough to prevent lost circulation. MPD dramatically reduced OBM losses into extremely high permeability fractures in the productive strata. The operator employed a Rotating Control Head (RCH) along with a gas-buster, choke manifold, fluid handling system, and flare system. This equipment allowed the operator to flow while drilling in the deeper high pressure/high deliverability zones and maintain an “at-balance” bottom-hole pressure in the shallower/lower pressure zones through judicious application of surface backpressure. The oil-based mud eliminated all issues with the sensitive shale formations. A mud weight (including ECD) of about 8.95 PPGE for most of the hole and a baseline LCM load proved sufficient to control lost circulation in most instances. When drilling through intervals with intense natural fracturing, the operator used slugs containing a higher LCM concentration comprised of a broad range of particle sizes. LCM slug materials included cottonseed hulls along with graphite, cellulosic fiber, and CaCO3 to cure/prevent partial lost circulation. In some extreme cases, the operator employed fresh water gel pills (“Reverse Gunk”) to combat total lost circulation. The operator developed a “Mud-Cap” technique to pull the Bottom Hole Assembly (BHA) when Total Depth (TD) had been achieved which improved well control and reduced OBM losses when running and cementing casing. Through producing consistent and economic results over a large number of wells across a large area, the OBM MPD program made the continuous and successful development of the entire field possible.
The ubiquitous challenge that is faced by chemical stimulation techniques, of any kind, has always been achieving an economic and efficient distribution of the stimulation solution across the entire exposed reservoir interval. Many have approached this problem from a chemical perspective and others from the use of additives for mechanical diversion; however the very nature of stimulation itself means that a changing injection profile will make efficient diversion by such techniques uncertain and unpredictable. Instead, rather than relying on serendipitous deployment techniques, the approach described and reported here places true mechanical diversion as part of the well construction process. This paper will completely describe the process and achievements to date, including successful application in a number of horizontal wells completed in the Austin Chalk, as part of an overall deployment plan.
Essentially, this new completion system comprises of multiple pressure actuated subs, distributed along the liner/casing. These subs, when activated, allow the lateral deployment of 40 foot needles, radially distributed at 90° phasing around the casing, into the unstimulated reservoir. These subs can be precisely located across pre-selected intervals and thereby provide certainty of acid treatment distribution. The acid is pumped through the needles themselves during stimulation, however production takes place through ports. A be-spoke debris basket may be run, after the stimulation treatment, in order to recover a suite of needle deployment indicators. This run, if performed, subsequently confirms the success of the deployment.
In order to prove the concept and avoid the high-cost environment of the North Sea, a low cost field trial location was sought and identified. An Austin chalk operator was identified that had an extensive horizontal candidate well set available for re-completion in open-hole. A number of candidate wells were identified and the wells were recompleted and stimulated with this new system. This paper will present the entire suite of data related to these deployments, stimulation operations, lessons learned, production impact and potential. This novel technology was greatly assisted, supported and delivered via the Joint Chalk Research (JCR) council, comprising of some ten operating companies that encourage, fund and drive the development of carbonate solutions.
Akinnikawe, Oyewande (Texas A&M University) | Chaudhary, Anish (Texas A&M University) | Vasquez, Oscar (Texas A&M University) | Enih, Chijioke (Texas A&M University) | Ehlig-Economides, Christine A. (Texas A&M University)
Previous studies have shown that bulk carbon dioxide (CO2) injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk because of aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO2 in a CO2/brine displacement. Two approaches to CO2/brine displacement are considered--an external brine-disposal strategy in which brine is disposed of into another formation such as oilfield brine and an internal saturated brine-injection strategy with which the produced brine is desalinated and reinjected into the same formation. The displacement strategies increase the storage efficiency from 0.48% for the bulk-injection case to more than 7%. A conceptual case study with documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is sufficient to store all the CO2 being generated by power plants in the vicinity for approximately 20 years only. However, the CO2/brine displacement increases storage efficiency enough to store the CO2 produced for at least 240 years at the current rate of coal-fired electric-power generation. Sensitivity analyses on relative permeability, permeability, and temperature were conducted to see the effects of these reservoir parameters on storage efficiency.
For bulk injection, increased permeability resulted in increased storage efficiency, but for the CO2/brine-displacement strategies, decreased permeability increased storage efficiency because this resulted in higher average pressure that increased CO2 storage per unit of pore volume (PV) and increased CO2 viscosity. Also, storage efficiencies for the displacement strategies were highly sensitive to relative permeability. There is an optimal CO2-injection temperature below which the formation-fracturing pressure is lowered and above which CO2 breakthrough occurs for a smaller injection mass. The CO2/brine-displacement approach increased capital expenditures for additional wells and an operating expense for produced-brine disposal, but these additional costs are offset by increased CO2-storage efficiency at least 12 times that achieved by the bulk-injection strategy.
As an industry, we are still in the early stages of the learning curve for shale gas drilling although many shale gas wells have been drilled in recent years. Data from over one thousand wells drilled in the Maverick basin since 2003 were retrieved from an internal drilling database. Among them are over two hundred horizontal wells from the Eagle Ford shale play drilled by 31 different operators between 2008 and early 2011. The analyses of drilling performance data of these horizontal wells offer the establishment of general practice guidelines and recognition of opportunities for improvement in Eagle Ford shale drilling.
Oil-based drilling fluid, or "mud?? (OBM) is a typical drilling fluid type currently used to drill from the surface casing shoe to the total depth (TD) in the Eagle Ford shale play. However, water-based mud (WBM) has also been used since the development of the Eagle Ford shale play. A comparative analysis was performed between oil-based and water-based drilling fluids to assess their performances and to identify the key challenges and potential areas for improvement when drilling in the Eagle Ford shale. The analyses included mud chemistry, drilling performance, mud weight and well architectures such as bit sizes, casing sizes and depths of the casing shoe, as well as lateral length. A statistical analysis (P10, P50, and P90) was also performed to evaluate industry-wide drilling performance such as drilling days for wells of various depths. Comparisons were made among different drilling fluid types and different operating companies.
The statistical analysis shows that although overall performance of water-based drilling fluids lags behind that of oil-base fluids in Eagle Ford shale drilling, a certain WBM system shows promising performance close to that of oil-based drilling fluids. The analysis shows that there is a general trend of decreased drilling days per footage over time and a large variation in total drilling days for similar well depths and trajectories. This indicates that although the drilling industry as a whole has improved drilling in the Eagle Ford shale over the years, there is still a large opportunity for improvement. One interesting finding is that some operators can drill wells in fewer days than the industry average even though their drilling fluid cost is slightly more expensive than the industry average. As a result of reduced drilling time, their overall drilling costs are reduced.
Lab test results with different fluid types show that the failure mechanism and shale-fluid interaction of the Eagle Ford shale is different from dispersion or swelling which are typical of traditional shales. The analyses and results of this study on drilling performance data provide lessons learned and general guidelines for current drilling practices and opportunities for improvement such as drilling fluid selections, mud weight, and well architectures in the Eagle Ford shale play.