Oil & Natural Gas Projects
Exploration & Production Technologies
Optimization of Infill Drilling in Naturally-Fractured Tight-Gas Reservoirs
To develop a methodology (using reservoir/fracture characterization and simulation models) to determine the optimum well type (vertical vs. horizontal), well pattern, and well spacing to maximize gas recovery from naturally fractured tight gas reservoirs.
Gas production from low permeability formations is hindered by the formations' capability to allow gas to flow to the wellbore. Geologic processes have created natural fractures in most formations that provide channels for gas to flow. Fractures not only enhance the overall permeability of many reservoirs but they also create significant permeability anisotropy. Permeability anisotropy causes the drainage area around the wells to be elliptical. Elongated drainage creates more production interference and drainage overlap between adjacent wells and increases the potential for leaving parts of the reservoir undrained. Knowledge of the orientation and magnitude of the anisotropy therefore has significant economic importance in developing and managing a reservoir. Such knowledge allows optimization of well placement for maximum recovery of gas from the reservoir with the fewest number of wells.
Schematic diagram showing that the rotation of offset wells eliminates drainage overlap and increases drainage of reservoirs with anisotropic permeability.
Operators typically drill wells in a standard pattern based upon available lease acreage and state laws that dictate the minimum allowable well spacing. Very seldom do the operators take into account all available information (or spend the extra money to collect this information) to optimize production from a given field. New Mexico Institute of Mining and Technology conducted an integrated reservoir characterization and simulation study in 1998 of three small pilot areas for several operators in the San Juan basin. The results showed a strong permeability anisotropy and that well spacing could be reduced from 160 acres to 80 acres. The additional gas recovery from the new wells was calculated to be 18 Bcf.
New Mexico Institute of Mining and Technology
British Petroleum (BP)
Soccoro, New Mexico 87801
Burlington Resources and BP were granted permission to site new well locations based on drainage area and drainage patterns of previously drilled wells. Typically, wells are drilled on a given well spacing and pattern (usually square) that is specified by the New Mexico Oil and Gas Conservation Commission. For certain formations, gas operators have been able to convince the commission to reduce well spacing so that additional reserves could be produced. This was the first approved deviation in the Mesaverde tight gas sandstone reservoir in the San Juan Basin, and the approval was a direct result of this project.
The U.S. Bureau of Land Management (BLM) recognized the importance and impact of the project on resource development and management of oil and gas in the San Juan Basin. New Mexico Tech conducted a study and completed a report for the BLM entitled "Oil and Gas Resource Development for the San Juan Basin, New Mexico: 20 year, Reasonable Foreseeable Development (RFD) Scenario Supporting the Resource Management Plan for the Farmington Field Office, Bureau of Land Management." The report was published in July 2001.
This study has demonstrated a methodology to:
Analytical and numerical procedures and tools were developed for production and well testing analysis of tight-gas reservoirs and applied to field studies. These procedures and tools address issues related to estimation of reservoir production/flow characteristics, determination of reservoir permeability anisotropy and well interference, delineation of the drainage volume/area, and evaluation of infill well potential. A description of these procedures and tools and their applications are documented in a series of papers presented and published in proceedings of Society of Petroleum Engineers conferences.
- describe reservoir heterogeneities and natural fracture systems,
- determine reservoir permeability and permeability anisotropy,
- define the elliptical drainage area and recoverable gas for existing wells,
- determine the optimal location and number of new in-fill wells to maximize economic recovery,
- forecast the increase in total cumulative gas production from infill drilling, and
- evaluate hydraulic fracture simulation treatments and their impact on well drainage areas and infill well potential.
The 30-year production forecast of the reservoir models predicted a total net increase in recoverable gas for 80-acre spacing for two pilot areas in the Mesaverde area. The forecasts were 26 percent and 44 percent over the predicted gas recovery of existing wells on 160-acre spacing. Extrapolation of the results from these two pilots across the Mesaverde producing area provides a preliminary estimate of an additional 7.8 Tcf that could be recovered by optimal infill drilling.
Map Showing the Mesaverde Pilot Area
Reservoir studies of the four areas have significantly different well/reservoir productivity, and demonstrate the range of importance that natural fractures and the associated reservoir permeability and permeability anisotropy have on drainage efficiency and infill well potential.
Optimization of infill drilling in the Dakota relies upon two inter-related features: (1) the degree of natural fracturing and (2) the depositional facies.
Based on the available data and the methods used, the optimum stimulation procedure for the Lewis Shale, throughout the San Juan Basin, is a single-stage, 150,000 lb foamed linear gel, hydraulic fracture treatment. However, based on preliminary results from a small number of completions, it is recommended that slickwater designs be analyzed further to determine whether they would have better results.
Current Status and Remaining Tasks:
This project is completed.
Project Start Date: September 28, 1998
Project End Date: September 30, 2003
DOE Contribution: Phase I - $542,644; Phase II – $557,387
Performer Contribution: Phase I - $116,912; Phase II – $158,097
NETL - Jim Ammer (304-285-4383 or email@example.com)
New Mexico Tech - Larry Teufel (505-835-5483 or firstname.lastname@example.org)
Final Report [PDF-4634KB]
Pilot Study Areas in San Juan Basin