Hydrofluoric (HF) acidizing in the Monterey shale has had a long history of success, dating back to a case study performed in 1999 (Rowe et al. 2004). A proper acid-design program is critical to the success of these types of treatments. However, proper placement technique carries the same importance as the acid design. This paper will review a placement technique that not only provided proper placement but also reduced placement time significantly. Monterey shale intervals commonly reach 1,500 to 2,000 ft in vertical height. To further complicate downhole work, intervals are not homogeneous; there are differences in natural fractures, permeability, and porosity. The goal of matrixacidizing treatments is to place the acid below fracture pressures. Formation differences, including degree of damage, can limit injection rates and increase the pump time necessary to place the acid. Physical well conditions, such as the cement bond, create other challenges to overcome. Placement time for these acid treatments often takes several days to complete and can require multiple service providers, such as production rigs, downhole tools, remedial cement work, and coiled tubing (CT) units. With consideration to these issues, several questions arise, such as how can the entire interval be successfully acidized, the number of required services reduced, and placement time decreased. Using the new placement technique, the entire planned completion interval can be perforated in a rigless manner, acid equipment can be moved in that is capable of producing sufficient injection rates to exceed the formation’s ability to accept fluid below the fracture gradient, and real-time downhole monitoring equipment is installed to provide the operator and service provider adequate data to make decisions and adjust as necessary while pumping.

Successful acid treatment depends largely on the method used to place the acid. Water-injection wells are commonly treated using coiled tubing (CT) and a high-pressure nozzle to increase the well's injection rate. This paper focuses on the comparison of two types of high-pressure nozzles, as used in a slotted-liner cleanout in a sandstone formation. A majority of the diversion techniques available are classified as mechanical, such as straddle packers, opposing cup tools, particulates, and perforation ball sealers. In addition, the industry uses a variety of chemical diverters, such as gelled acids and foamed acid. These options might work fine in perforated and cemented casing, but there are not many effective options available with respect to matrix acidizing of long, uncemented slotted liners in sandstone formations. CT acid jobs have typically used nozzles, such as the fixed nozzle, rotating-jet nozzle, and the fluid oscillating (FO) nozzle. However, the newest innovation in fluid-oscillating tools is the fluid-oscillating tuned frequency and amplitude (FOTFA) nozzle, which is more efficient than the previous fluid oscillating tuned frequency (FOTF) nozzles. This paper presents case histories that compare the results of acid jobs using rotating jet nozzles and the latest FOTFA nozzles. Four analogous water-injection wells were chosen for the trial and were acid stimulated using CT. Two wells were acidized using a rotating nozzle and the other two with the FOTFA nozzle. The wells are in the same field and were treated using the same acid design and pumping procedures.

Proposal In an effort to improve oil production at Elk Hills, located in Kern County, California, successful new methods for acidizing both horizontal and vertical Monterey Shale wells were developed. During 1999 and 2000, 21 horizontal Shale wells were drilled with unacceptable production results, even though the petrophysical evaluation indicated the wells should have great flow potential. The uncemented, slotted liners prevented the use of conventional stimulation techniques. Instead, the acid blend, placement, recovery, and flowback techniques using coiled tubing evolved and improved. Workover equipment optimization and utilization increased and time to market and operating expenses decreased. The results from acidizing horizontal wells increased oil production up to nine-fold. Due to the successful large-volume hydrofluoric (HF) acid jobs on the horizontal Shale wells, many old vertical Shale wells were acidized using the same technique, increasing average well production by 110 barrels of oil per day (BOPD) and more than 500 MSCF/D. As a result of the diligent, combined team efforts of the operations personnel and the pumping service contractor, the total acidizing costs were reduced by U.S. $2,300,000. These costs were reduced through blending acid in the field, field-testing the oil for additives, lowering spent acid disposal costs, and mixing acid on the fly. Field History NA Shale drilling began in the fall of 1999 with two horizontal wells placed in the N Shale and two horizontal wells placed in the A Shale. The wells were re-drills of existing vertical wells with 7-in. production casing cemented in place. The wells were kicked off above the zone of interest with build rates above 20°/100 ft using a 6 1/8-in. bit. The laterals were drilled with high-viscosity drill-in fluids (DIF), with 6% KCl water as a base fluid and a cost of approximately U.S. $60 per barrel. Calcium carbonate (CC) was used for fluid-loss additive (FLA). The expectation was that the wells would flow to the tank batteries at economical rates. Therefore, 3 1/2-in. slotted liners were run to total depth. External casing packers were used only to isolate fluid above the zone of interest. One mud company suggested that only a few gallons per foot of HCl acid would be necessary to dissolve the CC FLA. A second mud company stated that only a 50-psi differential into the wellbore would be necessary to recover the CC FLA. The first well was initially acidized with 2.5 gal of 17% HCl per foot of net pay (gpnf) through coiled tubing (CT). Nitrogen and CT were used to recover the spent acid. The first A Shale well would not flow. A 11/2-in. rod pump was initially installed, but was increased to a 2-in. plunger diameter after a fluid level shot indicated 4,288 ft of fluid above the pump. The relatively high build rates and small liner size prevented the rod pump from being set as deep as necessary to maximize the pressure drawdown. Production, however, increased from 9 BOPD + 69 MSCF/D (1 1/2-in. pump) to 303 BOPD + 1,650 MSCF/D (2-in. pump) in two months. In an attempt to increase production, the acid volume was increased to 28.1 gpnf of 17% HCl through the next three wells (two N Shales and one A Shale). The last well was foamed with nitrogen for diversion. Nitrogen and CT were used on all three wells to recover the spent acid. Beam pumping units (BPU) were installed on all three wells within two months of their initial completions to reduce the producing bottomhole pressure (BHP) and increase production rates. The third well was reacidized with 11.0 gpnf of 13.5–1.5% acid (foamed), but oil production decreased from 105 BOPD + 253 MSCF/D to 26 BOPD + 382 MSCF/D after being killed with produced water. The wells initially averaged 107 BOPD + 708 MSCF/D, declining to 33 BOPD + 533 MSCF/D in two months. Horizontal redrilling of existing vertical wells continued into 2000 with two more N Shale laterals and four more A Shale laterals using DIF for mud. With the same completion technique, the six wells initially averaged 244 BOPD + 628 MSCF/D, declining to 70 BOPD + 311 MSCF/D in two months.

After successful production from a few wells in a California field, two development/appraisal wells were drilled targeting the southwest flank of the structure. Based on experience with the offsets, it was expected that this sandstone formation would be fracture stimulated to mitigate formation damage. Most of the wells in California have intervals ranging from 1,500 gross ft to ~600 net ft. Fracture stimulation or matrix acidizing are common stimulation techniques used on these types of wells. Fracture stimulation was attempted because of very low permeability but was not successful. On the first well, several attempts were made to establish fracture initiation in different intervals; however, on each attempt, the fracturing pressure encountered was too high to safely continue the job. A fracture gradient of more than 1.1 psi/ft was estimated. After 20 days of unsuccessful attempts, the operator ceased fracture stimulation of the well, which was nearing the point of abandonment because producing oil or gas did not seem economically viable at this point. After carefully studying the matrix rock, a gas-assisted perforating process followed by foamed matrix acidizing was recommended as an economical solution to produce the wells. This gas-assisted perforating process uses an extreme overbalanced (EOB) condition by using energized gas to simultaneously perforate and stimulate a well in a single intervention. During an EOB perforating application, wellbore pressures will exceed the fracture gradient for several seconds to minutes while injecting wellbore and tubing fluids at high rates. This paper presents a case study of two unconventional tight-gas condensate wells where using a gas-assisted perforating process followed by foamed acidizing provided successful stimulation. The design considerations, stimulation technique, and job details are discussed.

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