Drilling and Completion Technology

External casing perforating pinpoints hard-to-reach pay treatment

A new perforating technique, coupled with other multi-zone stimulation advances, saves overall costs and increases production in West Texas

Tom Krawietz and Greg Hobbs, BP America; and James Rodgerson and Henry (Enrique) Lopez, BJ Services Co. USA

This article overviews the results of the new external casing perforating system applied in seven multi-stage wells recently treated in the West Texas Permian basin. Significant bottom-line cost savings and increased production, compared to previous conventional multi-stage treatments are documented. Described are the basic principles and application of the patented external casing perforating system, and how it compares to conventional methods.

A summary review of the seven well treatments further describes novel use of the tubing “dead” string to monitor actual bottomhole pressures during treatments. And application of an extended crosslink time modifier in reducing treatment volumes, to save nearly $25,000 per well, is reviewed.

TARGETING MULTIPLE PAY INTERVALS

Perforating multiple pay intervals to achieve optimum treatment coverage has long been a topic of considerable debate. There are many techniques, employing everything from mechanical zonal isolation to stress diversion and limited entry, and most of these have demonstrated reasonable records of success in the field.

Perforation selection plays a crucial role in well performance. The consequences of inadequate perforation coverage can compromise fracture optimization, limit production and result in missed pay. Multi-zone fracture treatments have been performed using a variety of methods ranging from limited entry to mechanical bridge plug or packer isolation. These techniques have been routinely applied to stimulate discrete intervals within a formation in an attempt to maximize the production of stringers.

One common method consists of perforating/ isolating each zone, then stimulating. Wireline is used to isolate the previous zone and perforate the next stage. Treatment of multiple intervals in this manner can be a costly and time-consuming process, but will ensure adequate coverage of each zone.

EXCAPE downhole system run on casing before cementing and perforating.

INNOVATIVE MULTI-STAGE PROCESS

A new multi-stage treatment process optimizes perforation/ treatment design by using a technique known as “External Casing Perforating” or EXCP to facilitate rapid treatment of successive zones. EXCP allows the operator to perforate and isolate individual zones in less than 30 min. between treatment stages. As many as 17 discrete intervals have been treated within a 13-hr period.

Moreover, this approach minimizes total treatment volume by using the flush from the previous stage as the pad on the next stage, thus placing less fluid on the formation. Time to first sales has been reduced from days to a matter of hours by eliminating bridge plug isolation and costly post-job clean up. Production from multiple horizons has been brought online quickly in one rigless operation without damaging and time-consuming shut-ins. This process has proven beneficial in horizontal as well as vertical completions.

This completion system, known as the EXCAPE* Completion Process, was developed and patented by Marathon Oil Co. and is provided through a technical alliance of Marathon, The Expro Group and BJ Services. The system comprises external perforating guns, a control line and isolation valves, all of which are run into the open hole with the casing, prior to the primary cement job, see accompanying figure. The system is placed into position by lining-up the open-hole gamma ray log with radioactive markers located on each gun module. This process allows the precise placement of each perforating module prior to the cementing operation.

Once cemented in place, each gun may be detonated in succession via the control line from the surface. After detonation occurs, a sliding sleeve is actuated, allowing an integral isolation flapper valve to fall into place thus ensuring complete zonal isolation for each ensuing stimulation stage. Latch-down or flow-through isolation valves may be incorporated into the system. To-date, most operators have preferred the flow-through type because once the completion process is finished, the well may be rapidly placed on production.

REDUCES TIME AND COMPLETION COSTS

The new completion process significantly reduces time to perforate between stages and helps eliminate costly job delays. The perforating mechanisms are made up on the casing as it is being lowered. A stainless steel, high-pressure tubing control line links each perforating gun mechanism on the external side of the casing and is run to the surface. Once the casing has been positioned properly, the primary cement job is performed, permanently cementing casing, gun mechanisms and control line into place.

Prior to the stimulation treatment, pressure on the control line selectively detonates the perforating mechanisms. The gun mechanism placed in the lowermost zone discharges at a lower pressure than does the gun above, and each successive gun above it discharges at a successively higher pressure. Monitoring the pressure on the casing during perforating verifies that the zone was perforated. Once the perforation module detonates, a flapper valve is actuated to isolate previously treated zones from pressure above the valve.

Up to 27 zones have been successfully treated in a single wellbore using this method, averaging nine zones per day. As many as 17 zones have been treated in a single 24-hr period.

Seven multi-stage wells were recently treated. In each case, six-to-seven fracture treatment stages were performed in a 24-hr period. Previous treatments using a bridge-plug and packer method took an average of 2.8 days. The cost reduction associated with EXCP included a total of $34,200 for 1.9 days of location costs (rig time, perforators, labor) and $28,500 for 1.9 additional days of fracturing equipment and associated costs. A conventional wireline-conveyed bridge-plug and gun approach can often take as long as four hours per zone and, normally, only four stages can be completed in one day. In contrast, the time between stages using EXCP can be reduced to as little as 15 min.

The required hydraulic horsepower for each well was reduced, too, as average pump rates per zone were lower than conventional treatments. Other reduced costs can include elimination of job delays due to perforating and placing isolation equipment, reduced treatment volume, and elapsed time to production, see summary table.

DEAD STRING REDUCES COSTS

A tubing (dead) string has also been effectively used to reduce treatment time and cost of “stage” fracture treatments. Tubing is suspended in the casing and the fracture treatment is pumped down the annulus. The tubing is used to monitor actual bottomhole pressures during the treatments to anticipate screen-outs and aid in more accurately modeling fracture geometry. In case of a screen-out the dead string can also be used to immediately reverse-circulate proppant out of the wellbore and allow the job to continue with the next stage. (Most conventional stage treatments are performed without a dead string, and a screen-out can delay the treatments since tubing must be run in the hole or a coiled tubing unit must be ordered and rigged up to clean out proppant).

CROSSLINK MODIFIER

Individual stage treatment volumes necessarily include a flush, to displace proppant-laden fracture fluid from the casing and to spot acid for the ensuing stage. These flush volumes can be significant, depending on casing size, depth and the number of stages to be treated. The flush fluid is normally fresh water or 2% KCl, containing surfactants and, often, 30 to 40 lb/1,000 gal concentrations of polymer (normally of the same type used in the main fracture fluid). The flush of the previous stage is displaced into the formation of the ensuing stage in its treatment.

If the flush of a previous stage is used as part of the fracture treatment for each ensuing stage, then total treatment volume (and cost) can be reduced. More precisely, each flush volume can be crosslinked and used as part of the pad for each of the next stages. Allowing the crosslinked pad to remain static for 30 min. to perforate, fluid friction encountered in resuming pumping could be substantial enough to appreciably limit fracture pump rates. To use the flush as part of the pad for the ensuing stage's treatment, the flush's crosslink time must be delayed for 30 min. – or the time to detonate and resume pumping – to minimize friction pressure and establish fracture pump rates for the next zone. This performance is beyond the scope of conventional crosslink time-modifiers.

In the seven multi-stage wells previously described, four used the new extended crosslink time modifier. The crosslink time of the fluid was delayed for the 30 min. needed for perforating, and enabled each flush to be used as part of each ensuing stage at fracture pump rates. The total average treatment was 332,000 gal of a crosslinked borate fluid. Total treatment volume of each of the four wells was reduced by an average of 221 bbl per stage or 1,381 bbl of fluid. Total cost was reduced an average of $24,700 per well and included 1,381 bbl of water, polymer, surfactants, biocide and two frac tank rentals, see summary table.

A significant benefit of this process is that, by reducing total treatment fluid volume, the potentially damaging polymer pumped into the formation is proportionately reduced. In the above wells, total treatment volume for each well was reduced by 1,381 bbl containing 30 lb/1,000 gal guar polymer. This reduced the polymer pumped into the formation by 1,740 lb. The reduction of polymer damage is viewed as critical to optimal reserve recovery.

REDUCED TIME TO SALES

An additional benefit from external casing perforating is the reduced completion process time needed for the well to be placed on production after treatment. In the wells described, the completion time for each well has been reduced to an average of 21.6 hr from 2.63 weeks (18.4 days) for the conventional bridge-plug and packer method previously used by the operator; 17.5 days of earlier production accounted for an average, theoretical $70,000 ($4.00/Mcf @1,000 Mcf/day) for each well. In addition, early and sustained flowback of the wells is considered beneficial to optimal reserve recovery.

Several factors contributed to the reduced completion time. These include: 1) flowing the well back immediately after the treatments (to make use of the induced hydraulic energy); 2) flowing through the EXCP isolation flapper valves; and 3) and the reduced volume of fluid to recover due to the reduced treatment volume. Additional reduced costs include those associated with: recovery of the 1,381 bbl of fluid per well not pumped, equipment, labor, rig time, disposal and other associated recovery costs, see summary table.

In the cases described, average cost of the treatments, inclusive of the external casing perforating, represents a net cost increase of 2.5% for each well, compared to conventional bridge-plug and packer methods with similar volumes. The net cost increase does not include 17.5 days of earlier production of $70,000 per well, nor the costs associated with the recovery of 1,381 bbl of fluid not pumped.

SUMMARY

In seven multi-stage wells recently treated, use of the new completion process reduced perforating time and treatment costs by allowing the treatment of six to seven discrete productive stringers in a 24-hr period. The cost reduction for each well averaged $34,200 for two additional days of location costs (rig time, perforators, labor, etc.) and $30,000 for two days of fracturing equipment. Use of a tubing dead string helped reduce treatment time and costs by providing a method to monitor actual bottomhole pressures. An extended crosslink time modifier reduced treatment volumes by 1,381 bbl and saved $24,700 per well by allowing the flush of a previous stage to be used as the pad for each ensuing stage.

Formation polymer damage was reduced due to the lower treatment volume. And $70,000 per well in earlier production was realized by reducing completion time from treatment to sales by 17.5 days by means of the reduced fluid volume, and immediate/ sustained flowback through isolation valves afforded by the EXCP. Importantly, the process included selective fracture treatment of six to seven productive zones (stringers), whereas only four stages were normally performed with conventional bridge-plug and packer. The value of the system to the operator was a 20.5% production increase for an additional cost of only 2.5% per well, for a net gain of 18% on their money.

The new process was more efficient, required less time, and was cost-competitive when compared to the conventional bridge-plug and packer method previously used by the operator. Simply stated, the overall cost increase associated with the new completion system was more than offset by savings and the production increase. 

ACKNOWLEDGMENT

The authors thank BP America and BJ Services Co. for providing the opportunity to write this article. They also thank Doug Walser and Greg Salerno of BJ Services, and Phil Snider of Marathon for their invaluable technical assistance.