New treatments can substantially increase leakoff and formation integrity pressures to solve deep high-pressure, high-temperature drilling challenges.

Deep wells below 15,000 ft (4,575 m) TVD are uncommon in California. The many attempts to drill at these depths have incurred high trouble costs, while some have not reached the target depth because of adverse formation conditions. Borehole pressure integrity (BHPI) technology may help prevent one major root cause of deep, high-pressure, high-temperature (HP/HT) drilling trouble: rock tensile failures that create severe lost circulation. Operators should use leakoff test (LOT) data to help determine low BHPI or fracture gradient conditions before designing BHPI treatments.
Recent deep Temblor exploration drilling activity in the San Joaquin Basin of California presented the opportunity for applying BHPI technology to help increase the near-wellbore fracture gradient (NWFG) in a long openhole section. After a revised treatment program was implemented, BHPI treatments successfully increased the NWFG to the desired pressure integrity.

Key factors: Why it works
The success of the BHPI process can be attributed to the following:
• the hoop-stress-increasing (HSI) chemical system can be pumped through the bottomhole assembly (BHA) and bit, eliminating two trips (one for BHA removal, another for BHA reinstallation);
• the treatment can provide long-term circulation control, allowing ample time for drilling the hole and setting casing or completing the well;
• operators can perform prejob tests of the drilling fluid and HSI chemical system mixture to determine the predictability of the chemical reaction and help ensure optimum downhole performance;
• the HSI chemical system does not set like cement and usually does not require waiting time before drilling ahead.
Less waiting time, little or no skin damage and much larger increases in NWFG are the main reasons for applying the new BHPI process.
Process description
The BHPI technology process encompasses the entire evaluation, placement and re-evaluation of treatments to help increase the integrity of a weak zone.
Prior review. Operators review the weak zone's data before arriving at the well site. Logging-while-drilling and measurement-while-drilling logs are reviewed for any data that could indicate the location of the weak zone. A temperature log, as well as resistivity logs, may indicate the location of a lost-circulation zone. In addition to log evaluation, other well information is also reviewed. The factors that determine the size of the job will be found in all well data.
Prior evaluation. When the zone is identified, an LOT should be performed as a baseline test with which to compare any improvement after the weak zone is treated. The LOT is evaluated for fracture-opening pressure and fracture-closure pressure. When the test is conducted and leakoff is achieved, the pressure is allowed to stabilize. Stabilization can take up to 30 minutes but should not exceed 30 minutes. The pressure should be stable with little to no decrease over a 1-minute period.
Laboratory testing. When the operators arrive on location, mud samples from the location are captured and analyzed. Compatibility testing is performed between the treatment system used and the specific mud system to determine reactivity and final composition. In addition, the spacers are tested with the mud system to determine the spacer's compatibility with the mud and treatment system.
Placement technique. When the LOT is complete and evaluated for results, treatment placement can begin. The placement techniques used to seal a single weak zone vs. those techniques used for a multiple weak-zone problem may be different. More than one treatment may be needed to seal multiple weak zones. The end of the work string (EOS) or the bit is positioned one yielded chemical system volume away from the uppermost weak zone. The EOS depth may be in the openhole region or the cased-hole region. When the EOS is below the casing shoe, the openhole region's pressure containment integrity should be confirmed to prevent improper placement.
Cleanout techniques. After the treatment is successfully placed and pressure-packed into the formation, the well can be bled off and the mud can be circulated, which will allow the drilling fluid system to be brought into satisfactory condition for cleanout. Once the treatment is complete, cleanout of the remaining material in the wellbore can begin. This application can allow the unused material in the wellbore to be removed without packing off the stabilizers and plugging the bit.
Post evaluation. Once the bit has been pulled into the previous shoe, a second formation test should be performed. The well should be pressured to a previously determined pressure. The procedures should be identical to the method used at the start of the process except that a leakoff may not be required if the desired BHPI is achieved. This consistency will allow adequate comparison of the data. If the agreed-upon pressure is not achieved, a second treatment can be sought.
Formation permeability protection
Core-test studies have explained the apparent lack of payzone permeability damage after HSI treatments, finding that the treatment systems have almost no filtrate loss and negligible filtrate penetration into rock-matrix permeability. The negligible core-test damage, evidenced by shallow filtrate penetrations, implies that perforation tunnels and hydraulic fracturing stimulation can easily communicate with permeability undamaged by HSI treatments. Only the LOT leakoff pathways in fractures and faults are sealed by inches of HSI treatment penetration.
Formation permeability damage
The following list shows the differences between lost-circulation material (LCM) gel pills; LCM mixed in mud; cement and gunk squeezes; and HSI systems.
LCM gel pills. Damaging filtrates from pills leak into matrix permeability. Filtrate precipitates plug pore throats. Filtrates change wettability to impair hydrocarbon flow. Polymer residues and fines in pills plug permeability. Salt LCM may cause salinity shock and formation-fines release or plugging.
LCM mixed in mud. Mud filtrates also may damage, like pill filtrates. Fines from LCM may invade and plug permeability.
Cement and gunk squeezes. These result in the same types of damage as gel pills and mud filtrates and can release fines that invade and impair permeability.
HSI systems. Near-zero filtrate loss barely penetrates permeability. Fines are chemically aggregated to prevent penetration into permeability (Figure 1).
Case histories
Job A of the Berkley Petroleum East Lost Hills No. 1 well treatment program includes data that continue to support the hoop-stress theory to increase NWFG and BHPI. The next case history (Job B) for Vastar Resources is the first application of a completely new BHPI chemical system designed primarily to enhance a formation's tensile strength, with some smaller degree of hoop-stress enhancement.
In Job A, a deep hole integrity problem encountered in the Berkley Petroleum East Lost Hills No. 1 well prevented drilling ahead. Methods such as LCM treatments along with cement plugs were used to improve the hole integrity in the upper Temblor before the HSI treatment process was implemented. Two treatments with a special type of lost-circulation mud-reactive chemical system also were initially attempted and improved the hole integrity, but the LOT (bottom curve in Figure 2) was still insufficient for drilling ahead into the next section.
After the second HSI job, a pressure test (top curve in Figure 2) showed an improvement of 1.11 lb/gal. The last pressure test performed was not a standard leakoff test but a formation integrity test (FIT). After the cleanout and FIT, the operator was able to drill into the transition zone of the thick Temblor formation and beyond to set the casing. This ability indicates the HSI treatments were maintaining the BHPI enhancements achieved earlier.
In late 2000, the Ocean Victory took a kick drilling a wildcat exploration well for Vastar Resources in a deepwater Gulf of Mexico well (Job B). To stabilize the well, a bullhead kill was performed. While killing the well, operators fractured an area below the shoe. So the rig could continue the well, the bottom 2,000 ft (610 m) of the hole was cemented and an area about 1,000 ft (305 m) below the shoe was left open to allow for sidetracking. The mud weight was decreased in the hole to achieve stability. The new BHPI process and an experimental TSE chemical system were selected to improve the formation integrity of the well. In this case, the process was modified to adapt to the different properties of the TSE system.
This process was performed with a stinger and mule shoe, chosen because this assembly already had been placed in the hole for setting cement plugs. A directional BHA was picked up and run in the hole to clean out the TSE system. After the TSE material was drilled through, a leakoff test was performed. After 10 minutes, the stable pressure was 1,182 psi, equal to a 15.68-lb/gal equivalent mud weight (EMW). The NWFG increase experienced after the job was 0.32 lb/gal EMW. The TSE material remaining in the hole was easily removed, and no tendencies for kicking off prematurely were seen. This gain allowed the operator to drill the planned section of the hole without losing returns.
Acknowledgements
The authors thank the management of Berkley Petroleum, Vastar Resources and Halliburton Energy Services for their support and permission to publish this paper. Joe Garcia and Daniel Bour are recognized for their help in organizing the field operations and conducting laboratory tests, respectively for the HSI treatment applications in the Berkley Petroleum East Lost Hills No. 1 well in California. The following also contributed to the description of the theory and rock mechanics equations: Fersheed Mody, Wolfgang Deeg, Ali Mese, Uday Tare, Calvin Kessler, Peter Pelton, Terry Hemphill and Don Whitfill. This article is a summary of SPE paper 71390.

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