CWwt 1S90, fADC/SPE Drilliw Confw-This pawr was prepe red fw Vesentation at the 1S9S tADC/SPE Drilliw CMferw held in Dallas, Texas, 3-6 Mti 1S9S. This paper ws selected for Wesenlatiw by an lADC/SPE Pregram Commitiee follewing review ef informalien contaln~h an abstrad submRted by the aufher(a). Centents of the peper, aa preaentad, have not baen reviewed by the Intamafimal Aaseciatiin of Drilling Centractora or the Society ef Petroleum Engineers and are subject to correefion by the a-s) w m~eriali aS WS~I~, d-~PSOEfllY M* any~a~~~he WC w SPE, tkir efficera, er members Paper8 preeanted qt the lAOC/SPE mear~s are suwect to publication raviaw by Edioriel Cmmittees cf the IADC and SPE. Elactronk reprcd~err, distriwm, w atore~ef any part ef this w fw eemm~ial mwa~~fhe Wffitan mnsenf ef the Seciety of Patrolw Eng*ra is @ibifed. Permission to mm h print is rastricfed to an abstract of net mere then W words: illuatratione may net be copied The abstract must eciWain -spiwous acknawtedgment & where and by whern the paper was presented. Wrte Librarian, SPE, PO. Box 83W3e, RWrdeon,~7~3-3e3S, U.SA., fax 01-972-9S2-9435. AbstractShale instability problems when using water-base drilling fluids have remained unresolved for decades because of a lack of knowledge and understanding of the shale hydration mechanisms. The industry has relied upon hydrocarbon-base drilling fluids for combating shale problems, but misconceptions have kept even those fluids from being utilized to their fullest advantage.With the use of hydrocarbon-base fluids now being curtailed because of environmental concerns, costs due to shale problems could escalate.The understanding of shale instability problems has been hindered by inadequate laboratory means of simulating contact of drilling fluid and shale under downhole conditions of stress and temperature. To address this situation Gas Research Institute has conducted a project in which laboratory equipment and procedures were developed to permit preserved specimens of downhole shale (cored in hydrocarbon-base mud) to be restored to in situ axial stress, horizontal stress, pore pressure and temperature prior to being drilled at a selected borehole pressure.Provisions were made for measurement of fluid transport in either direction between the circulating drilling fluid and the shale during an extended period of exposure. The borehole pressure was then reduced incrementally to observe for borehole failure and obtain a measure of effect of the &llling fluid on the relative stability of the shale.The above procedures have been used to study a wellknown troublesome Cretaceus shale cored using oil-base mud at a depth of about 5,500 ft in Block 4 of the U.K. sector of the North Sea.~is paper presents data showing that the aqueous activity of either a water-base or hydrocarbon-base emulsion drilling fluid can be adjusted to develop osmotic pressure that will cause water to enter or be extracted horn a low-permeability shale. The hydraulic differential between the borehole pressure and far-field shale pore pressure ...

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^

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Sustained casing pressure is a serious problem that is prevalent in most of the oil producing regions of the world. Annular pressure can be a significant safety hazard and, on a number of occasions, has resulted in blowouts. Sustained casing pressure results from the migration of fluids in the annulus. The most common path for migration of fluids is through channels in the annular cement. To safely and economically eliminate sustained casing pressure on a well in the Gulf of Mexico, W&T Offshore, Inc. utilized an injectable pressure-activated sealant technology to seal channels in the annular cement of their well and eliminate the casing pressure. The mechanical integrity of the well was restored, saving over $1,000,000 compared to a conventional rig workover. Introduction Migration of fluids through the annuli of wellbores can result in a condition known as "sustained casing pressure" or "SCP". SCP is pressure that rebuilds in the annulus after being bled down.1 With age, the integrity of all wellbores deteriorate. Cracks and fissures develop in the annular cement due to a number of factors related to cement composition, thermal stress, hydraulic stress, compaction, wellbore tubulars, and the downhole environment. The most significant cause of sustained casing pressure in the outer casing strings is a poor cement bond that results in the development of cracks and annular channels.2 The cracks and microannulus channels through the cement provide a path for high-pressure fluids to migrate from deeper strata to low-pressure strata or to the surface. If left uncontrolled, SCP represents an ongoing safety hazard and can cause serious or immediate harm or damage to human life, the marine and coastal environment, and property.3 A significant flow of high-pressure fluids to a low-pressure strata results in an underground blowout. A significant flow of high-pressure fluids to the surface results in an irreducible casing pressure at the wellhead and the potential for catastrophic failure of wellbore integrity. SCP is a pervasive problem for the oil and gas industry. According to the records of the Minerals Management Service ("MMS") of the United States Department of the Interior, SCP affects over 8,000 wells in the Gulf of Mexico.4 Conventional Remediation Risks The conventional remedy for outer casing SCP is to perform an expensive and risky workover of the well using a rig. In the past, the industry has been reluctant to cure SCP problems on most wells based on a cost/benefit analysis of the relative risks. A conventional rig workover is a dangerous operation. Personnel can be injured or killed. Equipment can be damaged or destroyed. Blowouts or spills pose a significant environmental risk. The costs and risks of the conventional rig workover solution exceed the costs and risks associated with the current sustained casing pressure practices.5 The rig workover procedure requires removal of the tubing and injection or squeezing cement in an attempt to block the cracks and channels through the annular cement. Depending on the location, porosity and permeability of the cracks and channels, the cement squeeze may or may not be successful in sealing the paths for the migration of the fluid through the annulus. A cement squeeze is a costly procedure with a questionable probability of success. Cost-Effective Alternative As an alternative to a rig workover, a safe, cost-effective sealant process has been developed that eliminates the SCP by sealing the annular channels that provide the paths for the migration of the fluid through the annulus. Tests and actual job histories have shown that this sealant can be injected into the annular channels even after attempted injection with normal mud / cement mixtures have failed.

An ultra-high pressure (UHP-30,000 psi) downhole pump (DHPTM) is being developed for jet-assisted drilling. With this technology, drilling penetration rates in gas and oil wells can be increased 1.5 to 2.5 times. The prototype downhole pump was built for laboratory and field experimentation under a program with the Gas Research Institute. A second generation prototype is being supported by the U.S. Department of Energy - Morgantown. Current development is focused on the DHP system that develops the UHP fluid stream used to assist the drill bit. The pump is located just above the drill bit. Its rated output is 22 gpm at 35,000 psi. The DHP is about the same size as and is handled like a conventional drill collar. Power to drive the DHP is taken from the conventional mud stream. Surface mud pump pressure is elevated approximately 1,500 to 2,000 psi while maintaining conventional flow rates downhole Five field experiments were conducted with the first prototype. Observed ROP ratios varied from 1.1 to about 3.5 times conventional rates. The second prototype is currently being tested in the laboratory. Introduction The goal of jet-assisted drilling is to increase the rate of penetration (ROP) in deeper oil and gas wells, where the rocks become harder and more difficult to drill. Increasing the ROP can result in fewer drilling days, and therefore, less drilling cost. In the early 1970s, the potential advantages of applying high-pressure, 15,000 psi, jet technology to increase rates of penetration (ROP) were demonstrated by Maurer et al. (1973) and by Fair (1981). They were able to demonstrate ROP enhancements with high pressure jet drilling of between 1.2 and 2.9 times conventional rates in tests conducted in Florida and Texas. Both Maurer and Fair used jet drilling bits without mechanical cutters, requiring the entire fluid stream to be pressurized. This resulted in extremely high power requirements, 2,800 and 11,200 hydraulic horsepower, reliability problems, and safety concerns. During the late 1980s and early 1990s, FlowDril developed a system for ultra-high pressure, 34,000 psi, jet-assisted drilling. The system was described by Butler, et al (1990) and by Veenhuizen et al. (1993). About 40 gpm of the down hole mud stream was pressurized with pumps at the surface, 600 hydraulic horsepower, and conducted to the drill bit through a special dual-conduit drill string. This allowed a high-velocity jet of drilling mud at the bit to be directed at the bottom of the hole to assist the mechanical action of the bit. The system required separate high pressure surface piping, standpipe, and kelly hoses, a dual swivel, and a dual conduit kelly. Twenty-two field projects, 11 in West Texas and 11 in East Texas, totaling about 90,000 feet drilled, were conducted through Grace/FlowDril, a joint venture with Grace Drilling Company, to assess feasibility of jet-assist and to develop system reliability. An example of the effectiveness of jet-assist is shown in Figure 1. The average, joint-by-joint ratio of the jet-assist ROP to that of the offset between 4,000 and 10,000 feet was 2.1. The data shown in Figure 2 is from a test well in East Texas in 1992 after reliability of the system had been improved. P. 559