A new process helps maintain borehole pressure integrity.
Scott Kelley is drilling manager for Headington Oil Co. Ron Sweatman is cementing technology leader and James Heathman is cementing technology adviser for Halliburton Energy Services.
A new treatment for increasing borehole pressure integrity could save operators as much as 50% in well construction costs by eliminating the rig flat time and casing programs previously required to combat the loss of returns when drilling through weakened formations.
Halliburton Energy Services' Drill-Ahead Process (DAP) and its related chemical systems enable the use of higher density drilling fluids to control pore pressures and prevent borehole collapse by increasing the frac gradient near the borehole.
The DAP chemical system, when placed downhole and mixed with drilling fluid, undergoes chemical reactions that convert the fluids into small aggregates that are dispersed into the drilling fluid and carried a short distance into the formation. The resulting rubber-like material effectively molds itself into fractures, seals off flow paths, increases the fracture gradient and allows drilling to continue.
Successful application allows higher drilling and cementing circulation rates, helping to optimize drilling performance, improve hole cleaning and provide excellent zonal isolation through better mud displacement during primary cementing. Preliminary results show that the DAP treatment may minimize skin or formation damage in the zones of interest by reducing filtrate invasion.
Challenges: Causes and costs
Insufficient borehole pressure integrity is a significant challenge in drilling deep, high-pressure, high-temperature (HP/HT) wells. This problem frequently is encountered in South Texas, but has been seen in many other areas where depletion, leaking faults or poor rock properties have weakened shales or sands. Returns often are lost when mud weights are close to pore pressures and borehole integrity pressures.
Drillers setting casing to isolate normal pressure zones from high-pressure zones can encounter problems if poorly sealing formations exist at the casing shoe or the cement job does not provide a good hydraulic seal. This formation seal failure can be caused by natural, in situ stresses that cause weak points or by natural fractures and faults in the rock.
Often, additional pipe strings must be installed to allow drilling with narrow margins between pore and fracture pressure profiles. A survey of major operators indicated that if a reliable, quick method was available to increase borehole pressure integrity, an average of 25% of well construction costs might be saved, mostly from reduced rig flat time and casing program costs. Potential cost savings for deepwater wells have been estimated at between 30% and 50%.
Treatment technology
The new DAP treatments are effective because:
• they can be pumped through a bottomhole assembly, often eliminating the need to trip pipe;
• long-term circulation control is provided;
• formulations are chemically predictable and verified by wellsite tests; and
• treatments allow drilling to continue immediately, unlike systems involving cement and polymer gels.
Figure 1 illustrates an example procedure for placing a DAP system in a formation. The chemical system, separated by spacers, is pumped down the drillpipe. After the first spacer is circulated to the bit, pumping is stopped long enough for the annulus to be closed at the surface. Drilling fluid is pumped down the annulus between the drillpipe and the casing, and at the same time displacement fluid is pumped down the drillpipe to push the DAP system through the bottomhole assembly and out the bit nozzles. This causes the DAP system and drilling fluid to mix in the space between the bit and the formation. The resulting chemical reaction will form a material that has a rubber-like consistency with:
• extremely low filtrate loss;
• fast bridging in narrow flow pathways such as fractures and faults;
• self-molding tendencies to provide a more effective seal;
• rapid widening of fractures;
• rapid increases in viscosity to values too high to measure with common laboratory instruments;
• extremely high extrusion pressures that pack the aggregates together in flow pathways;
• self-diversion to other flow paths after the initial paths of least resistance have been sealed;
• resistance to limited swab pressures;
• resistance to dilution by cross-flows caused by rapid gelation;
• limited penetration (1/64 in. to 1/8 in.) into formation matrix permeability;
• sustained and substantial increase in near-wellbore hoop stresses by limited fracture closure; and
• increased casing-shoe borehole pressure integrity through simultaneous sealing of annular channels and formations.
Crank it up
Some field applications have used DAP systems that were modified to achieve faster downhole mud reaction times and much stiffer consistency of the rubbery aggregate. Theoretically, as the viscosity of the aggregate increases, the extrusion pressure increases when entering similar-width flow paths in the formation.
Headington Oil's B-1 well had experienced lost returns and gas influx. When each of the four DAP treatments was formulated with increasingly higher chemical concentrations of the active ingredients, engineers found higher concentrations resulted in higher borehole pressure integrity values and greater resistance to swab pressures.
DAP treatment aggregates may form flexible pressure seals that complement existing pressure seals formed by mud cake. DAP seals are impervious to temperature variations, corrosive formation conditions and to drilling, completion and acid stimulation fluids. DAP sealing aggregates created wider fractures with much smaller volumes of material than mud mixed with lost circulation materials (LCM). When additional DAP treatments are required, increased wellbore pressure (Pw) above initial treatment squeeze pressures may pack more aggregates in the initial fracture wings and further widen the fracture. Sustained widening of fracture widths may maintain adjacent alterations in formation stress fields and allow a higher Pw during drilling ahead.

Protecting formation permeability
DAP treatment penetration into the formation matrix is limited by mud cake permeability, bridging of solid fines, filtrate viscosity increases from chemical reactions in the pore throats, and limited filtrate volumes. When core tests were performed to determine if the DAP treatments caused skin damage, the minor skin damage observed led researchers to believe perforation tunnels can easily communicate with undamaged permeability. This opinion was reinforced by cases in South Texas where production from DAP-treated wells compared favorably to that of untreated wells. Future studies will evaluate DAP chemical system removal by chemical dissolution and high swab pressures. One DAP system contained an acid-soluble component that helps remove the aggregate during acid washes.
Field tests and case histories
The first DAP treatment was field-tested when an unexpected high-pressure water-kick caused an offshore well control problem. The drillpipe rams in the blowout preventer were activated to contain the sustained high pressure. The formation-induced pressure at the surface casing shoe 4,400 ft (1,342 m) below the mud line was higher than the leakoff test fracture pressure of 13.5 lb/gal equivalent density. The operator was concerned that the applied pressure might have broken down the shoe, possibly creating a hydraulic fracture and allowing a sustained water flow into the fracture and up behind the surface casing into a shallow sand.
After several unsuccessful attempts to regain full circulation, stop the drilling fluid losses and control the suspected water flow, all of which incurred expensive rig time, the operator agreed to try an experimental DAP treatment and chemical system. Immediately before the DAP treatment was pumped, a temperature log was run inside the drillpipe past the point at which water influx was suspected. A nodal analysis of the temperature data indicated a sustained water flow of 20 bbl/min, or nearly 30,000 b/d. Water was traveling up the open hole and into a channel behind the surface casing at the casing shoe, which explains why the previous treatment attempts had failed. These treatments had likely been severely diluted by the high-rate water flow, thus failing to plug the channel at the surface-casing shoe.
The experimental DAP treatment system was designed to resist dilution. The first treatment attempt successfully plugged the annulus around the casing shoe with a running squeeze pressure substantially above the shoe's leakoff test pressure. Based on the hydrostatic head of the static fluid column and the water-formation-induced surface pressure, the original 13.5 lb/gal pressure integrity at the shoe was increased by 5.1 lb/gal, making it capable of holding a pressure of 18.6 lb/gal equivalent density.
While drilling the B-5 well at 13,760 ft (4,197 m), the crew encountered lost circulation, and despite the use of three LCM pills, no improvement was noted. After the well was squeezed with the DAP system, full circulation was regained and a drilling liner was successfully cemented. The suspected interval was identified as a faulted shale interval that was most likely leaking drilling fluid up into another formation with lower integrity.
After an intermediate casing string at about 11,800 ft (3,599 m) in the J-19 well failed to test to the desired integrity for the next hole section, a test with a retrievable packer confirmed there were several collar leaks in the casing string below the top of the cement. When a cement squeeze and an LCM pill failed to solve the problem, the DAP chemical system was used and an integrity increase of 1 lb/gal was achieved. The well reached the next liner setting point without further problems.
When no cement was found in the float joint of an intermediate casing string and the shoe failed to test in the J-23 well, the DAP system was used to squeeze the shoe, increasing the integrity from 15 lb/gal to 18 lb/gal. The well was drilled to the next desired casing point without further problems.
Severe lost circulation was encountered while the J-26 well was being drilled at 13,000 ft (3,965 m), requiring the mud weight to be cut from 15.5 lb/gal to 13.5 lb/gal. The suspected interval with low integrity was a drawn-down gas reservoir that was confirmed to have a pore-pressure equivalent of about 6 lb/gal. The sand was treated with a DAP system and a buildup of 0.7 lb/gal was achieved, allowing the well to be drilled another 700 ft (214 m) and a liner to be set.
Lessons learned
Field tests indicated DAP treatments can significantly decrease well construction costs and shorten the time to begin commercial well production. Successive treatments, which may be necessary for long intervals, may cumulatively increase the fracture gradient. Pressure integrity of several types of rock can be restored and certain rock defects repaired with the DAP system, allowing the rock to withstand higher borehole pressures. In addition, shoe tests and poor cement sheaths in the annulus may be repaired simultaneously with a single DAP treatment right after a leakoff test.
Acknowledgments
This article is a synopsis of Paper No. AADE 01-NC-HO-42, presented at the American Association of Drilling Engineers 2001 National Drilling Conference in Houston, Texas, March 27-29, 2001.

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