07123-04

Goal
This project seeks to demonstrate that dramatically increasing the total volume of fluid production in high water cut oil wells can effectively increase recovery in fields where circumstances will permit very high rates of water production and disposal. The approach to be demonstrated for increasing total fluid production is a combination of the use of radial jetted laterals and high volume progressive cavity pumps.

Performers
Kansas Geological Survey (University of Kansas Center for Research), Lawrence, KS
American Energies Corporation (AEC), Wichita, KS

Background
High water cut production is a problem in many mature oil fields that have either undergone water flooding or produce with a strong water-drive mechanism. Efforts to maintain production or increase recovery from these marginal fields can falter on the high cost of water handling and disposal. Technologies are needed to increase the recovery of oil from the high water cut wells producing in these fields, allowing them to continue to produce economic volumes of oil and avoid abandonment.

The project is a demonstration of the drilling of horizontal laterals from an existing wellbore in a high water cut (>97%) formation to dramatically increase its productivity, and the subsequent pumping of high volumes of water and oil from the well using an efficient progressive cavity pump (PCP). The laterals will be created using a high pressure stream of water (jet-drilling). The increased volume of water will be disposed of in an injection well where the injectivity has similarly been enhanced through the drilling of jet-drilled laterals. By increasing the total volume of fluid produced (and thus the total volume of oil) by a factor of perhaps four (or more) in a situation where the handling and disposal of the additional water production does not involve any significant additional cost, the producer should enjoy an increase in net cash flow. This would enable marginal fields to remain on production and incremental oil to be recovered.

The project involves the Penner No. 12 well producing from the Viola Formation in American Energies Corporation’s Hillsboro Field in Marion Co. in Central Kansas. The well will have a number of radial jetted laterals added to the wellbore and a PCP installed. Net oil production is expected to increase four-fold, from 10 to 40 bopd. A nearby injection well (Penner No. 12 SWD) will be deepened and recompleted with radial-jetted laterals to increase water injection capacity. A number of reservoir and well evaluation analyses, including reservoir simulation, will be undertaken both before and after the drilling and completion operations. An economic evaluation of the entire process will be completed. As well, an assessment of the nearby Durham Center Field will be completed to determine the potential for applying this technology field-wide at that location.

Deliverables for this project will include a series of reports on the various tasks as they are completed and a final report integrating the results of the project and providing guidelines for its application elsewhere.

Updated Background
The project obtained a one-year no-cost extension to August 23, 2010 as unforeseen issues arose due to the downturn in the economy. Also, during evaluation of the reservoir and field production, oil was determined to remain updip from the production well as attic oil, residing along the crest of the structure. This crestal area was prematurely abandoned when well locations became submerged and inaccessible with construction of a Corps of Engineers lake in the 1950’s. A 1000 ft lateral was proposed to be drilled from the vicinity of the current production well, the Penner #1, using a hybrid coil tubing drilling rig to tap updip locations. However, fluid levels measured late during summer 2009 in the Penner well indicated less than hydrostatic pressures suggesting that the reservoir is compartmentalized whereby the Penner #1 well location may not be connected to the structural crest or the Penner #1 has drained the updip locations through gravity flow. This latter scenario seemed to have been confirmed in that checking of production from a nearby well on another operators lease has recently seen an increase in production from 100 bbls to over 300 bbls per month. Reservoir simulation of this lower pressure regime indicated insufficient oil reserves accessible to the lateral. These findings compelled us to consider relocating the lateral to an adjoining field, Unger Field, also operated by AEC. Hydrostatic pressure has been confirmed in this new location with similar high volume, high water cut oil production as at Hillsboro Field.

New Location for Lateral Drilling
The alternative site identified is Unger pool located 10 miles south of the Hillsboro Field. It is operated by American Energies and the Devonian age Hunton reservoir is another porous dolomite interval. The Hunton dolomite resides at 2800 to 2850ft MD in Section 19-Range 21 South- Range 4 East of Unger Field in Marion County, Kansas. The field was discovered in 1955 and has produced 8.6 million barrels. Today, 17 wells produce with a total annual production of 13,572 bbls. In 2008, production was an average of 2.2 BODP per well.

Location of the proposed lateral is projected to be between 1000 ft and 1500 ft in length and follows the crest of a ¾ mile long northwest-trending anticline located in the southern part of Unger Field in Section 19. Local structural relief on the Section 19 anticline is 30 ft with an oil column around 40 ft. in this area of the field. Thicknesses of pay locally ranges from 12 to 25 ft. Recent pressure data obtained from this reservoir indicates hydrostatic condition with a strong water drive. The lateral would be drilled and competed open hole to tap potential isolated reservoir compartments of the weathered, karsted, and fracture dolomite reservoir. In addition, the crestal area of this reservoir has likely been underproduced since water coning occurred in the vertical wells, many of which are now plugged. A cost-effective, strategically drilled lateral extending between the plugged wells offers substantial potential that will be estimated by a simulation model that will be completed in March 2010.

Potential Impacts
The benefits of this technology demonstration would accrue from its widespread application to other fields having the three key characteristics necessary to make it successful, namely: high water cut production, existing water handling and disposal facilities with the capacity to handle and inject substantially larger volumes of water with minimal increase in cost, and reservoirs (both producing and injection) amenable to the jetting of radial laterals. Application of the technology in such fields would lead to an adjustment in the decline curve of field production, with an increase in oil rate and ultimate recovery. The cumulative benefit would be determined by the total number of fields where this technology is ultimately applied. Production of the remaining reserves would be accelerated, and there could also be some incremental oil recovery by virtue of an expanded drainage area resulting from the laterals. The national economic benefit from any incremental increase in domestic oil production would be an increase in tax revenue, royalties and regional economic benefits.

Accomplishments
The Project Management Plan and the Technology Status Assessment were completed for this project.

Pay characteristics, as part of screening for laterals technology - that of a sucrosic (intercrystalline) dolomite with moderate amounts of chert nodules - were defined. The team also defined viable approaches to drilling laterals, and assessed the likelihood of successfully penetrating significant distances beyond the borehole.

A literature review and web research was carried out to define alternatives to water jetting to drill a 300 ft lateral. This reaffirmed proposed priorities for lateral drilling: azimuth control and a reach of 300 ft.

The team obtained more data on old abandoned wells from AEC and made additional maps and cross sections. Preliminary simulation modeling of lateral was completed to evaluate scenarios for oil recovery to aid in decision making on position and length of lateral.

The project was granted an extension in August 2009 since activities became delayed due to unforeseen consequences of the faltering economy. During the year leading up to the extension, initial evaluations also led to considering alternatives to using radial jet drilling due to the critical need to obtain an extended reach lateral with accurate knowledge of azimuth and trajectory. Comparison of the state-of-the-art technologies was provided in a Technology Status Assessment dated November 19, 2008. Key findings stated in that report pertaining to an in depth review of lateral jetting via the literature and visits with vendors of lateral jetting technology include:

1. Data on unfractured oil producing reservoirs indicate that water jets with pressures of 10,000 psi (69 MPa) will cut rock with permeabilities over one md (Kolle and Theimer, 2005). Rocks with increasing permeability will require less pressure while rocks that are tight will have threshold pressures that are in excess of a 14.5 x 103 psi (100 MPa) up to levels of 25 x 103 psi (170 MPa). Theoretically, the jet erosion of permeable rock depends on the diffusion of “jet stagnation pressure” in the pore space to create tensile loads that will break out the particles of rock (Kolle and Theimer, 2005).
2. An advertised length of laterals is a maximum distance, while the actual length can be considerabye less due to adverse reservoir heterogeneities encountered as the tool exits into the borehole.
3. Heterogeneities in the reservoir such as chert nodules, fractures and associated cements, or irregular clay layers will tend to create erratic penetration rates and possibly change the trajectory of the hole or impede or stop penetration. Large tight and hard nodules and lenses such as those comprised of chert can stop penetration all together, thus the size and distribution of these hard drilling constituents must be avoided, if possible, by carefully evaluating intervals to be jetted, to increase the chances that the water jetting will cut to maximum depths. Alternatively, when a porous reservoir is bounded by hard layers, the jetting tools will tend to stay within the confines of the more porous and easily-cut reservoir rock.
4. Another attribute of the water jetting is that once the hole is created, acid can be used to remove formation fines and enhance porosity and permeability in the rock cut by the lateral. However, formations that have adverse water and acid reactions such as clays might plug the pores through caving and swelling. Thus, in general, penetration of soft formations can lead to the collapse of the holes once drilling has been accomplished. Again, careful consideration of the physical properties and reaction to drilling fluids of the candidate reservoir should be evaluated in advance of jetting.

The Technology Status Assessment also discussed microhole coiled tubing as an alternative to the lateral jetting. Key findings include:

1. Microholes are less than 4 ½ inch in diameter, the size of the surface or completion casing or tubing or holes sizes that is commonly used in industry. Holes between this and 6 inches are considered slimholes. Slimholes typically use a rotary rig to drill a vertical borehole, while microholes (as identified by the DOE) utilize coiled tubing to drill both vertical and lateral boreholes, rapidly and cost efficiently. These characteristics are key ingredients in the considerations of using microhole drilling. DOE demonstrated the use of microholes to drill new wells to efficiently develop mature, compartmentalized reservoirs in the U.S. (DOE Microhole Drilling Conference, 2005). The lower cost and rapid drilling of the microhole could led to a “Walmart approach” to infill drilling, thereby resulting in multiplying the reservoir contact area to tap remaining resource beyond the reach of existing infrastructure (wells).
2. Microhole technology is used by international companies to create digitate smart laterals in a pinnate fashion from a single vertical borehole. The laterals radiate out into a thick reservoir or multiple pays to optimize recovery from a single location due to environmental (e.g. Alaska’s North Slope) or logistical limitations (offshore platform) on drilling. Microholes allow more holes to be drilled with a smaller footprint and when used in conjunction with cost effective, high resolution imaging of the reservoir it becomes a powerful technique to enhance production from existing fields or find and/or delineate new fields cost-effectively. The smart nature of the laterals is that fluid produced from individual laterals is monitored and used to control flow rate.
3. Coiled tubing jet drilling is a hybrid version of the microhole. The design of Tempress Technologies calls for a 3 1/2 inch hole drilled with 2-inch coiled tubing (http://www.tempresstech.com/ book_shelf/6.pdf). Testing by Tempress has included: 1) steerable positive displacement downhole motor assisted by high pressure water jets and 2) a high pressure jet drilling rotary tool where pressures of 10,000 psi pressure provides sufficient force to cut rock.
4. A new application of microholes being considered in this study is to recomplete an existing vertical borehole to revitalize oil production. A window will be milled into casing or the open hole to be used to access the reservoir. The lateral will then be drilled with coiled tubing that fits inside the production casing using a short turning radius bottom hole assembly including a steerable mud motor.
5. A directional drilling alternative using hybrid coiled-tubing was recognized as the most economic of available technology. This technology parallels the Microhole concept championed by Roy Long with DOE.

The research team was able to find a coiled-tubing drilling contractor, ADT out of Yuma, CO, in early 2009 and worked toward contracting from either Weatherford or Baker-Hughes to use their slimhole lateral drilling technology recently introduced into the Midcontinent. The KGS and American Energies reported on this at the RPSEA Small Producers Meeting in Wichita on April 30, 2009.

Further mapping, reservoir simulation, and testing of wells in Hillsboro Field led to concerns about pressure depletion and diminished oil reserves, so a decision was made to move the project to nearby Unger Field located 10 miles south of Hillsboro Field. Mapping and log analysis in the southern portion of Unger Field confirmed a structurally high, thick porous Hunton dolomite reservoir where reservoir pressures are close to hydrostatic. The potential for IOR using laterals appears to be significant due to possible compartmentalization and underproduced areas between once producing vertical wells that likely suffered from water coning.

The proposed location of the 1000 to 1500 ft long lateral in Unger Field is in Section 19-21s-4e. Discussion is underway with lateral drilling vendors regarding the drilling of laterals in the most cost effective and successful manner, in this nearly depleted marginal reservoir. The goal was to drill the lateral in the May 2010 timeframe in time to evaluate and report by the end of the project on August 23, 2010. Subsequent delays lead to a revised drilling date of December 2010.

Current Status (January 2011)
The key tasks to be undertaken are outlined below.

Evaluate the potential of the Hunton dolomite reservoir in the vicinity of the proposed lateral well
The lateral drilling site has moved to Unger Field in the Hunton dolomite reservoir. Structure and isopach maps of the reservoir and overlying strata have been completed. Well logs, sample and core descriptions have been interpreted to define an optimal well location along the crest of the anticline in southern Unger Field. The geological model is currently being refined to include layering and distributing reservoir properties among the layers so that production can be estimated for the proposed lateral. Nearby vertical production wells are mostly abandoned and their production histories are mixed and incomplete so barrel tests are being used to supplement production for history matching to validate reservoir simulation.

Evaluate the injectivity of the Arbuckle disposal well
Existing Arbuckle disposal wells have sufficient injectivity in Unger Field to accommodate the estimated increase in produced water. Thus, the research team will focus the RPSEA funds to offset costs to drill the lateral.

Drill and evaluate lateral in Unger Field
The research team has been working on the basic equipment to drill this well cost-effectively while having technically sound equipment and accurate delivery of the lateral. After negotiating with several vendors, it was determined that the technology is not cost-effective for this application. The go ahead was given by all parties to drill a 1700 ft lateral in the Unger Field guided by azimuthal gamma ray tools. The research team met to discuss logistics of drilling and decided on a drilling date in December 2010.

• Coiled-tubing drilling, at least at this stage, will not be used since it is more expensive than a conventional rig (generally higher mob-demob costs). Conventional drilling is as reliable as coil to deliver laterals and operation is more familiar to the small operator.
• Slimhole drilling is no longer considered since the cost is too high in drilling a new well. Thus, the original premise of using slimhole coil is not economic at this stage due to high costs, in particular, mob/demob. The team decided to drill a new well rather than reentry to optimize drilling and completion conditions. It is also now apparent that it is best to drill with standard downhole tools ranging from 5 7/8 to 8 ¾ inch vs. slimhole due to costs.
• Drill radius long enough to not stress capabilities of downhole tools but not too long to slow down drilling.
• Use a smart casing plan to optimize cost drilling issues and production volume considerations. Consider casing to minimize impact of lost circulation or gas zones, eliminate sticking pipe, design casing shoe to keep cement out of open hole completions, and allow at least drilling well balanced or slightly underbalanced to limit borehole skin damage.
• Use a good mud system to avoid introducing foreign material such as from open mud pit to avoid damage to downhole mud motor. Remove sand and solids with desilters and desanders.
• In a production setting with considerable well control and basic reservoir characterization (elevation, pay interval and thickness) MWD tools need only to provide basic information, but are preferably close to the bit with these relatively thin pays. Azimuthal recording of sensors is important when in the reservoir to establish spatial heterogeneity, location and inclination of the bit (x-y-z location of the bit). Suite of wireline tools can be run after the lateral is drilled to obtain essential suite of measurements including gamma ray, porosity, and resistivity, e.g., triple combo log.
• Develop a team-based well trajectory plan so all understand the lateral’s path relative to the reservoir and provide clear input and feedback for geosteering the lateral.
• Refine initial engineering simulation of lateral incorporating well data obtained.

Evaluate project performance
The researchers will compare incremental oil recovery with the costs of drilling, pumping, and water disposal and analyze the overall economics of the methodology. A “best practices” guide will be prepared to help other producers interested in applying this approach in: 1) evaluation of lateral production wells through refined geomodel development and reservoir simulation and 2) recompletion strategies using laterals to increase production in high volume, high water cut mature oil reservoirs..

Evaluate recovery potential of the remainder of Unger Field
The researchers will assemble and analyze logs, cuttings, and well completion and production histories from the rest of Unger Field and history match production/pressure history via simulation studies. They will evaluate the potential for incremental oil recovery via the demonstrated methodology in Unger field wells. Projected water production rates for maximum oil recovery will be estimated and used to determine if the Arbuckle disposal well will be capable of meeting disposal requirements. An economic evaluation of the projected costs and incremental revenue will be completed.

Technology Transfer
Throughout the duration of the project all of the results and information collected, including the analyses and final reports on each task, will be made publically available.

Project Start: August 25, 2008
Project End: August 24, 2010 (extended)

DOE Contribution: $248,385
Performer Contribution: $271,056

Contact Information:
RPSEA – Martha Cather (prrc.nmt.edu or 575-835-5685)
NETL – Chandra Nautiyal (Chandra.Nautiyal@netl.doe.gov or 281-494-2488)
University of Kansas – W. Lynn Watney (lwatney@ku.edu or 785-864-2184)