Some systems already deployed in the GoM, offshore Africa
Bruce Beaubouef,Managing Editor
BHGE says that its DEEPFRAC multi-stage fracturing service is designed to improve the efficiency and economics of offshore completions. (Courtesy BHGE)
As the offshore industry drills further down into ultra-high-pressure reservoirs, advances in well completion technology will become increasingly important. And the downhole service sector has responded with an array of new completion technologies in response, including advances in frac-pack products, openhole gravel-pack services and packers, and cementing systems. A number of these new technologies were highlighted at the recent Offshore Technology Conference in Houston.
Case studies
One technology highlighted at OTC was BHGE’s DEEPFRAC multi-stage fracturing service, which won an OTC Spotlight award. BHGE says that the service leverages tools and techniques perfected in unconventional plays to improve the efficiency and economics of offshore completions. Using ball-activated sleeves and flowback control technology, BHGE says that the service simplifies operations, accelerates completion times, and enables rapid stimulation of 20-plus stages in a single trip.
BHGE says that a major operator recently deployed the DEEPFRAC service in the Gulf of Mexico. The operator had a 30,000-ft (9,144-m) well located in 10,000 ft (3,048 m) of water, and had planned to execute a conventional cased-hole multizone completion. However, as the well was being drilled, formation challenges prevented it from being cased to total depth (TD) in the deviated section, eliminating any option of proceeding with a conventional cased-hole completion.
Having already invested significant drilling capex in the well, the customer did notwant to abandon it. But in order for the well to be completed to plan they would need to side track. This would add an estimated 10 rig days. To make matters worse, a severe weather event was looming in the Gulf, and the well would need to be temporarily suspended before work could begin, adding an estimated nine more rig days.
Faced with significant delays and costs, the customer contacted BHGE for a contingency lower completion solution that would keep the well plan on track. The BHGE team recognized this as an ideal application for the DEEPFRAC deepwater multi-stage fracturing service.
The original completion plan called for the stimulation of five stages across a 1,000-ft (305-m) interval. This was because the conventional tools slated for deployment had long space-out requirements, restricting segmentation of the interval to no more than five large stages.
Uniform treatment distribution across these broad areas would be a challenge, as fluids take the path of least resistance. Fortunately, the DEEPFRAC service allowed the customer to re-think the completion design because its modular sleeves enable precise placement of fracture initiation points at any desired location along the reservoir interface, as close as 13 ft (3.9 m) apart.
The customer first considered segmenting the 1,000-ft interval into 15 stages, but ultimately decided on six stages, with no change in the pump program. The revised completion design also included specialized hydraulic-set packers and reactive-element packers to isolate water zones. This level of design flexibility and reservoir contact efficiency would not have been possible with conventional tools, says BHGE.
Working under a tight deadline, the BHGE team performed all critical tests and verifications of the tools under strict quality control standards. The flexibility of the lower completion equipment allowed mobilization of existing inventory in less than a week’s time—a stark contrast to the typical six-month delivery timeframe for conventional equipment. Meetings between the BHGE team and the customer were ongoing throughout the entire process to ensure the proper contingencies were in place, and to closely monitor weather conditions.
Because the DEEPFRAC service can be performed in openhole wellbores, the rig team was able to immediately deploy the completion assembly. No fluid displacement, casing, cementing, perforating, or wellbore clean-up was required, saving an estimated nine days upfront. All tools were run to TD without any issues, and the packers were set at the necessary locations along the reservoir to isolate the water.
Approximately 1.4 MMlb (635,029 kg) of proppant was delivered into the target interval in a single nonstop pumping operation that took only 32 hours. BHGE officials report that no tool movement was required, and that the aggressive pumping schedule presented no challenges to the downhole equipment. Pressure signatures were monitored throughout job execution and provided confirmation of each sleeve’s position as disintegrating frac balls were dropped from surface. BHGE acoustic sensors were used to verify ball launcher actuations, and identified two launch delays that could have jeopardized two of the six stages. BHGE says that its personnel were able to make quick corrections and ensure that the ball drops and sleeve actuations were properly synchronized. According to BHGE, the first ball to reach each sleeve shifted its frac ports open for treatment delivery, and the second ball simultaneously shifted the frac ports closed and production ports open for flowback.
Weatherford has introduced the WFX0 openhole gravel-pack system, which it says enables gravel-pack completion of multiple openhole zones in a single trip. (Courtesy Weatherford)
According to BHGE, by using the DEEPFRAC service versus a conventional multi-zone system, the operator was not only able to avoid the estimated additional 19 rig days it would have taken to suspend the well, wait out the storm, and side track; but they were also able to accelerate the completion phase by an estimated 30 days – a combined savings of approximately 49 days. BHGE says that this job was the third successful application of the DEEPFRAC service in the Lower Tertiary, marking a notable trend toward an unconventional, more economic approach to offshore completions.
Elsewhere, Schlumberger reports that its new openhole packer, which enables isolation of unwanted zones, has been used successfully offshore Angola. Total E&P Angola had planned commingled production from stacked sedimentary layers located in the Kaombo deepwater development. Targeting multiple reservoir layers with each well would reduce well count and therefore capex. Field A consists of five layers. In one instance (well 1), oil from one of the layers was found to be incompatible with the rest, and could not be commingled due to the risk of asphaltene precipitation. In a second well (well 2), a water-bearing layer was located between the oil layers. Both wells required isolation of the problematic layers while producing the layers above and below.
Water breakthrough in one or more reservoir layers is a risk associated with commingled production. The rate of production would have to be reduced to delay the event and costly remedial operations undertaken for water shutoff when the breakthrough eventually occurred.
This was the challenge presented by the lower three of the four layers targeted by well 3 in field B. Water shutoff capability was highly desirable in this well, according to Schlumberger. Total’s completion technique of choice was openhole gravel packing because the complexity of multizone frac-pack technology was deemed high risk, and the cost was prohibitive.
Alternate path screens and shunted swell packers have traditionally provided a solution for multizone openhole gravel packing, but the packer swelling process is slow, increasing costs – especially in deepwater applications – while the rig waits. Pumping gravel before swelling is complete can cause the gravel to enter the packer element-wellbore annulus, preventing an effective seal.
Schlumberger says that the new OSMP OptiPac service mechanical packer addresses all these concerns. The company says that the mechanically activated packer is hydrostatically set in a matter of seconds as the setting tool moves through it.
Gravel packing can begin immediately without affecting the seal, saving a significant amount of rig time. The packer is equipped with field-proven alternate path shunt tubes. Once the uppermost zone is packed, gravel is diverted through the shunt tubes to the next zone, and the process repeats until all the zones are packed.
OptiPac openhole gravel-pack service and OSMP packers delivered complete gravel packs in wells 1 and 3, confirmed by downhole gauge data and mass balance analysis. Two OSMP packers straddling the unwanted zone in well 1 and shunted blanks across the zone enabled isolation of the zone, reducing the well count by two and saving more than $100 million.
Halliburton has introduced its HCS AdvantageOne offshore cementing system, which it describes as representing a “next-generation cementing and well-control pumping system.” (Courtesy Halliburton)
A single packer in well 3 provided the ability to seal off the lower reservoir layers by setting a high-expansion plug in a section of blank pipe, in the event that water breaks through in the future. Cost-effective water management gives Total the opportunity to produce at an accelerated rate and improves ultimate recovery. Reservoir simulations show that water shutoff can result in an incremental production of 1,000,000 boe from field B.
Well 2 is scheduled for openhole gravel-pack completion at a later date; it will use two OSMP packers with shunted blanks in between to isolate the water zone. Total is currently evaluating the deployment of additional OSMP packers in future wells.
Elsewhere, NOV reports that a major operator offshore Norway has deployed its i-Con monitoring sub for gathering and understanding dynamic data recorded during well operations. The compact, memory-based monitoring sub is equipped with an electronics package consisting of sensors, batteries and memory for use in coiled tubing and drillpipe operations. The operator typically logs their 95⁄8-in. cemented liner after installation, as they need to ensure that shallow gas zones are properly isolated. The i-Con tool was run directly above the liner top to log the downhole forces and verify the downhole dynamics during the liner installation. The i-Con data, as compared to the surface rig data, provided a clear picture on how the liner installation was conducted. NOV says that this resulted in improved understanding of torque transfer from surface to liner top combined with a deeper insight on how cement displacement impacts downhole torque during cementing operations.
NOV reports that a major operator offshore Norway has run its i-Con tool to verify the downhole dynamics during the liner installation. (Courtesy NOV)
Other technologies
Other downhole service firms are also offering new well completion technologies. Weatherford has introduced the WFX0 openhole gravel-pack system, which recently won an OTC Asia Spotlight award. The company says that the WFX0 system is the industry’s first fully integrated gravel-pack system to achieve an API/ISO V0 rating, which validates that it has been tested to the market’s highest standards with zero gas leakage. The technology enables gravel-pack completion of multiple openhole zones in a single trip.
Halliburton has introduced its HCS AdvantageOne offshore cementing system, which it describes as representing a “next-generation cementing and well-control pumping system.” The company says that it is specifically designed to address the complexities of deepwater and ultra-deepwater cementing, with versatility for use in shallow waters. Halliburton says that the cementing system is optimized for an optional 20,000 psi manifold, to allow work in water depths that exceed the pressure limit of conventional equipment. The new 20,000 psi manifold increases well control ability and can be used for pressure testing deepwater subsea blowout preventer (BOP) stacks.
Halliburton says that a key component of the HCS AdvantageOne offshore cementing system is the 25-bbl, three-compartment configurable mixing system and an integrated six-pump liquid additive system with dynamic inventory management. The liquid additive automated metering and pumping unit enables access to an array of additives required to tailor slurry systems for the demands of offshore wells, including ultra-deepwater wells.
In addition, the company says that the metering/pumping unit facilitates logistical efficiency with the use of totes for liquid materials storage, rather than further limiting the available bulk storage on an offshore vessel for dry goods. Halliburton says that the pumps have a completely new stainless steel design which provides instantaneous response for adjusting fluid-flow rates, and delivering advanced blend accuracy. The mixing system, liquid additive system, and the 80-ft3separator (dispenses dry cement) are all controlled by the same PLC (programmable logic controller) system for enhanced precision of the mixing proportions of dry materials, mix water, and fluid additives, matching the actual slurry to the job requirement design.
TETRA Technologies has introduced TETRA CS Neptune, which the company describes as a high-density, solids-free, zinc-free, and formate-free completion fluid developed for deepwater and complex high-pressure wells that require heavy clear brine solutions to control well pressure during the completion phase. The company says that until now, zinc brines or cesium formates had been the only options for completion fluids. The company says that TETRA CS Neptune addresses the environmental challenges facing offshore oil producers seeking an alternative to zinc brines, which are classified as “marine pollutants” in the US and have been prohibited for use in the North Sea since the 1990s. Cesium formates replaced zinc brines in the North Sea and, until now, were the only viable option. Tetra says that the new completion fluid provides another option that meets the environmental requirements for the Gulf of Mexico and the North Sea, and can be used in other sensitive environments.
