Development and Testing of Downhole Pump for High-Pressure Jet-Assist Drilling S.D. Veenhuizen, SPE, FlowDril Corp.; and D.L. Stang, SPE, FlowDril Corp.; and D.P. Kelley, FlowDril Corp.; and J.R. Duda, SPE, U.S. Dept. of Energy; and J.K. Aslakson, SPE, Amoco Corp. Abstract A second generation prototype ultra-high pressure (UHP30,000 psi) downhole pump (DHP) for jet-assist drilling has been tested in the laboratory and downhole The development and testing program has been supported by the Gas Research Institute (GRI) and the U.S. Department of Energy Federal Energy Technology Center (DOE-FETC). It is anticipated that with development of this technology, drilling penetration rates in the harder, slower drilling formations in gas and oil wells could be increased 1.5 to 2 times through jet-assist of the drill bit. As with the first generation prototype DHP, the ultra-high pressure pump is designed to be located downhole in the BHA just above the drill bit. It is rated at an output pressure of 30,000 psi at about 20 gpm. Power to drive the DHP is delivered downhole via the conventional mud stream through elevating the surface mud pump pressure 1,500 to 2,000 psi using conventional flow rates downhole The operating principle and general arrangement of the DHP pump is discussed along with the operating behavior and performance characteristics. The pump has been tested eight times downhole in three commercial gas wells in the Travis Peak Formation of East Texas and a granite test well in Norway. Rate of Penetration (ROP) enhancements observed were up to 1.5 to 1.6 times conventional penetration rates. Testing in the laboratory to evaluate design issues that have limited downhole operating hours is summarized in terms of fluid sealing, mechanical strength, and fluid erosion. Jet-assist drilling ROP enhancement is also discussed in terms of laboratory drilling test results and field drilling results utilizing the DHP in East Texas and Norway. The main technical design challenge remaining before commercialization of the DHP technology is erosion within the pump when drilling very abrasive formations. Introduction The purpose of ultra-high pressure, jet-assist drilling is to increase the ROP in the drilling of deeper gas and oil wells where the rocks become harder and more difficult to drill. Increasing the ROP can result in fewer drilling days, and therefore, more economical drilling of gas and oil wells. To accomplish ultra-high pressure, jet-assist drilling requires a jet-assisted drill bit and a source of pressure. The source of pressure is a UHP DHP. In. late 1993, FlowDril and the Gas Research Institute (GRI) began development of a DHP based on FlowDril technology previously developed in pumping and sealing high pressure drilling mud. A first engineering prototype was designed, built and tested. Results of field experimentation with the first prototype were reported in Ref. 3. To accelerate development and commercialization of the DHP technology for ultra-high pressure, jet-assist drilling, FlowDril, in coordination with GRI, contracted with the U.S. Department of Energy (DOE) in late 1994 to develop and test a second generation prototype. DOE recognizes the benefits of advanced technologies to the gas and oil industry, and as such, manages a portfolio of drilling related research, development, and demonstration (RD&D) projects. The DOE's program is implemented by the Federal Energy Technology Center through one of its field offices located in Morgantown, WV These drilling-related projects support DOE's ultimate goal of facilitating development of the Nation's large natural gas resource base and maintaining market-responsive supplies at competitive prices. The RD&D program is highly coordinated with GRI activities and resources are leveraged when beneficial to the programmatic needs of both organizations. A more comprehensive treatment of DOE's oil/gas drilling-related RD&D is provided in Ref. 1. P. 183^

A new class of underbalanced drilling fluids being developed under U.S. Department of Energy sponsorship was recently successfully field tested. The fluid utilizes hollow glass spheres (HGS), also known as glass bubbles, to decrease the fluid density to below that of the base mud while maintaining incompressibility. A previous paper, SPE 30500, described the rheological properties and laboratory behavior of HGS fluids. An HGS fluid was formulated in the field and used to drill two wells in Kern County, California in the fall of 1996 for a major operating company. Concentrations of up to 20% by volume were used to decrease the fluid density to 0.8 lb/gal (ppg) less than normally used in the field. The techniques employed to mix and maintain the mud, the rheological properties measured in the field, and a discussion of future applicability of HGS fluid are addressed here. The field tests demonstrated that HGS drilling fluid can be easily and safely mixed under field operating conditions, is compatible with conventional drilling muds and rig equipment, and can be circulated through conventional mud motors, bits, and solids control equipment with little detrimental effect on either mud or equipment. Potential benefits of using these fluids include higher penetration rates, decreased formation damage, and lost circulation mitigation. When used in place of aerated fluid they can eliminate compressor usage and allow the use of mud pulse MWD tools. These benefits improve drilling economics. These and other recent advances in technology have spurred interest in underbalanced drilling to the highest level in 30 years. Industry-wide surveys indicate that more than 12% of wells drilled in the United States in 1997 will intentionally employ underbalanced techniques. Introduction The U.S. Department of Energy (DOE) recognizes the benefits of advanced technology to the oil and gas industry. Consequently, DOE manages a portfolio of drilling related research, development, and demonstration projects designed to reduce cost and increase process efficiency. This program is implemented by the DOE's Federal Energy Technology Center and is a market-driven balance of near-, mid-, and long-term efforts. These drilling related projects support the department's ultimate goal of developing the nation's large natural gas resource base and maintaining market-responsive supplies at competitive prices. Lightweight solid additives (LWSA) for drilling fluid density reduction were tested in the laboratory and in a test yard in drilling rig compatible equipment during 1994 and 1995. The Department of Energy (DOE) published a final report on this Phase I testing in the fourth quarter of 1995. The primary objective of the project since that time has been to test underbalanced drilling products in actual field operations. The LWSA tested consists of hollow glass spheres (i.e. glass bubbles) manufactured in the United States and commonly used as a filler material for other lightweight products. The spheres have an average specific gravity of 0.37 and average collapse strength of 3,000 psi. The spheres average 50 microns in diameter. The goal of the DOE project is to use the glass bubbles to generate drilling fluids having densities less than that of the base fluids. Much of the intangible cost of drilling wells is time sensitive, so techniques, which increase rate of penetration, are core to the DOE program. Underbalanced drilling products are investigated because of their potential for increasing drilling rate, as well as their potential to retain maximum well productivity by minimizing drilling induced formation damage. The LWSA fluids represent one such underbalanced drilling technology. A more comprehensive description of DOE drilling related research and development was provided in an earlier paper, SPE 30993. Mobil Oil Company provided the first opportunity to test LWSA in a field operation in September 1996. P. 699

Horizontal wells are effective alternatives to fractured vertical wells in several reservoir types, including low-permeability sandstones and shales. An understanding of fluid flow relationships is a prerequisite for efficient use of horizontal technology. The pressure-buildup data analyzed here were recorded in a horizontal completion in a lowpermeability gas-bearing shale. The well was drilled and tested to verify laboratory and computer modeling research. After the general solutions were developed, the data were analyzed to describe reservoir properties and the effectiveness of the completion. Results of the type-curve analysis indicate that the contributing well length was shorter than the actual drilled length and that the contributing reservoir thickness was less than the typical net pay. Numerical modeling was used to verify the calculated parameters. Results fully support the well length and reservoir thickness determined through type-curve analysis, indicating that an unstimulated horizontal well completed in a heterogeneous formation may be insufficient to link the full vertical extent of the reservoir to the wellbore.

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Recently, there has been a heightened interest in the use of horizontal wells to more efficiently drain both oil and gas reservoirs and to compensate for negative producing situations such as coning. The potential producing situations such as coning. The potential applications of horizontal and high-angle wells have led to increased efforts to quantify the expected production increase from these types of completion production increase from these types of completion methods in a variety of geologic settings. Simulation of these alternative completion methods using mathematical models provides a cost-effective method of predicting their performance and allows for predicting their performance and allows for sensitivity analysis of reservoir properties. The performance of horizontal and high-angle completions was simulated for marginal marine and lenticular low permeability gas reservoirs of the Upper Cretaceous Mesaverde Formation underlying the east-central Piceance Basin. Results of the simulations show that Piceance Basin. Results of the simulations show that production from horizontal wells of intermediate production from horizontal wells of intermediate length can be expected to be four times higher than that of vertical, stimulated wells draining large areas. The advantages of high-angle wells in lenticular sandstone environments remain unquantified, but a reasonable potential exists, especially when methane from deeply buried coals is considered. Introduction The United States has a vast natural gas resource contained in very low permeability reservoirs, particularly in western basins and trends. Three Rocky particularly in western basins and trends. Three Rocky Mountain basins included in this resource base are the Green River of southwestern Wyoming, the Piceance of northwestern Colorado, and the San Juan of northwestern New Mexico and southwestern Colorado. Recent estimates of gas-in-place (GIP) for the Greater Green River and Piceance Basins are 4,971 Tcf and 420 Tcf (140.8 Tm3 and 11.9 Tm3). Recoverable gas is estimated to range from 8 to 16 percent of the resource base. In many areas, development of this resource has been limited for several reasons, including complex geology, low wellhead prices, and low deliverabilities of many wells. Drilling and completion technologies also have limited the contributions from tight gas sands — hence, the need for researcefforts that attempt to find economical methods to extract the resource. Advanced technologies, that is, the implementation of alternative completion methods to improve the performance of low permeability gas reservoirs, is one area performance of low permeability gas reservoirs, is one area currently under investigation. In this report, the performance of high-angle and horizontal wells in low performance of high-angle and horizontal wells in low permeability, regionally extensive (blanket) and permeability, regionally extensive (blanket) and lenticular sandstones is evaluated through an integrated effort employing a finite-difference reservoir simulator. The use of horizontal wells in oil reservoirs located throughout the world has led to several-fold increases in production compared to vertical wells. If alternative technologies are as effective in tight gas sands as they have been in oil reservoirs, then the exploitation of these unconventional gas resources will become more economically feasible and the reserve base expanded. The east-central Piceance Basin provided the study area for the modeling investigation. Figure 1 shows the location of the basin as well as the specific area of interest within the basin. The east-central portion of the Piceance is an excellent source of portion of the Piceance is an excellent source of data as well as a "proving ground" for the application of horizontal and high-angle completions, since it has been well characterized in terms of geology and productivity. P. 299