Non-frac stimulation technologies mark progress too

Sept. 22, 2008
Although the oil and gas industry’s buzz over the hot gas shale plays in North America has pushed fracturing technology advances to the forefront, other production stimulation technologies continue to make progress as well.

Although the oil and gas industry’s buzz over the hot gas shale plays in North America has pushed fracturing technology advances to the forefront, other production stimulation technologies continue to make progress as well.

The rest of the well stimulation industry would do well to heed the example of innovations occurring in fracturing, according to Barry B. Ekstrand, Weatherford vice-president, reservoir stimulation.

“We should never forget that the proverbial lemmings do a great job of following an established path as they fall off the cliff,” he says. “The analogy is relevant for us in our industry, as we must recognize when innovation creates a new path, an opportunity to build on success.

“We rightly seek efficiencies and often adapt our past successes to new situations, but we must not miss out on balancing efficiency with innovation opportunities. Effectively striking that balance ensures that we will not miss out on opportunities to take successes and improve upon them.”

Fracture-related technologies

There are several fracture-related technologies marking progress in the realm of production stimulation.

Ekstrand points to improvements in and integration of borehole microseismic monitoring, along with frac treatment monitoring and controls and analytical technologies that “will enable increasingly accurate real-time optimization of frac treatments.”

Also on Ekstrand’s technology advance wish list are completion tool technologies that dramatically decrease the time to complete fracture stimulation activities in multizone wells.

“By reducing or eliminating the time for preparatory activities between frac stages, huge efficiency gains are achieved; the impact is magnified when on a horizontal well,” he says. “Metallurgical technology and tool configuration are critical to the success of these systems that are subjected to high-pressure, highly erosive conditions.”

Stimulation monitoring

A virtual, real-time integrated collaborative environment can maximize returns by applying a “model, measure, and optimize” strategy for well stimulation, according to Halliburton’s Dan Gualtieri, global product champion, Houston, and Christi Gell, VeriStim program manager, also of Houston. Gualtieri and Gell provided written responses to Oil & Gas Journal Technology Forum’s queries.

Such an environment is created with The Digital Asset’s VeriStim stimulation monitoring and optimization service. This workflow combines a stimulation job with microseismic monitoring, distributed temperature sensing (DTS), and optimization of the stimulation model post-job to enable the most effective drainage of an asset.

“The key factor in this workflow that adds the value is integration,” Gualteri and Gell wrote. “The process moves beyond simply measuring data to understanding how these data relate to the geology, to the production, and to what is done next. This workflow is reservoir-focused rather than well-focused.

VeriStim service consists of several components that when combined can result in optimized stimulation results:

  • An experienced, multidiscipline team working collaboratively with the operator.
  • Fracture stimulation.
  • Monitoring the created fracture using microseismic analysis.
  • Monitoring fluid movement in the near-wellbore area using DTS.
  • Post-treatment analysis and reporting.
  • Optimization of the stimulation model to enable the most effective drainage of an asset.

According to Gualteri and Gell, operators working with the VeriStim service teams gain enhanced capabilities in two important areas:

  • Optimized reservoir stimulation and hydrocarbon production.
  • Monitoring and control of the stimulation treatment in real time for maximum treatment efficiency in both vertical and horizontal wellbores.

Acidizing

As oil and gas production comes increasingly from challenging reservoirs, the industry will need to push the performance envelope for acidizing chemicals, contends Mary Van Domelen, product manager, near-wellbore stimulation, in Halliburton’s Cairo office.

“This will take acidizing from what has traditionally been considered a commodity service into the high-tech arena, requiring not only advances in acidizing chemicals, but also in the area of engineering design, execution, and treatment monitoring,” she says.

“One example is our integration of our state-of-the-art acidizing simulator, STIM2001, with fiber optic [DTS] treatment monitoring service, StimWatch.”

She also cites advances in the area of environmentally improved acidizing chemicals:

“It is undoubtedly difficult to develop an acid corrosion inhibitor that will stand up to the corrosive environment of hydrochloric acid at high temperatures and then biodegrade in North Sea water at 20° C.

“Halliburton researchers screen ingredients for environmental acceptability at the very first stage of product development, enabling provision of all services required of our customers, whether working in the Norwegian sector of the North Sea, in the Gulf of Mexico, or any land base operation around the world.”

One of the current trends to exploit both carbonates and sandstones reservoirs is to drill deeper, looking for horizons in high-pressure, high-temperature (HPHT) environments, says Don Conkle, Schlumberger vice-president, stimulation services.

“Such harsh conditions are making some of the conventional acid-based materials unable to perform,” he notes. “New ways to create conductivity channels in carbonate formations by etching rock with solid acid materials are definitively a cutting-edge technology that will decrease the inherent and serious corrosion problems associated with such environments.

“From a well completion point of view, the ability to complete such HPHT wells with more regular casing materials will signify a reduction in completion cost, as the fluid that will be pumped is noncorrosive.”

In terms of sandstone acidizing, still one of the major obstacles to overcome are the secondary and tertiary reactions of conventional hydrofluoric (HF)-based acids, so new chemistry that will not rely on HF will definitively be a breakthrough, Conkle adds.

For both carbonates and sandstones, an area where more technologies will impact the success of the stimulation treatment are diverters. Conkle cites as examples of new concepts or chemistry diverters that are nondamaging, self-activated, and degradable under reservoir conditions.

Scale management

Van Domelen also points to advances in diversion technologies that will have “profound” effects on the success of scale management efforts.

“Having the right scale inhibitor, brine, and overflush is only part of the scale management process,” she notes. “The success of a scale inhibitor treatment also depends on the placement efficiency. The scale inhibitor should be placed so that all water producing intervals accept a sufficient quantity of the total treatment volume.

“If significant permeability or pressure variations are present in the interval to be treated, treatment fluid will enter the zones with the higher permeability and lower pressure, leaving little fluid to treat the other zones, which potentially can be the water producing zones.”

The challenge is even greater in long horizontal wells with significant permeability and pressure contrast, Van Domelen adds: “To achieve a more uniform fluid coverage, the original flow distribution across intervals often needs to be altered. The methods used to alter this are called ‘diversion’ methods. The purpose is to divert the flow from one portion of the interval to another.

“In response to this challenge, a viscosified scale inhibitor system was developed. The system comprises a linear (noncrosslinked) water-based fluid system, a standard scale inhibitor for downhole scale squeezing, and a breaker to achieve controlled gel breaking downhole.”

Other diversion methods that are commonly used in the industry include a newly developed particulate that degrades over time at temperature and, with the presence of aqueous fluid, completely disappears for a nondamaging diverting and fluid loss control material, according to Van Domelen. Foams or ball sealers can also be used for altering the flow during a scale inhibitor treatment, she adds.

Cement slurries

One area that is commonly overlooked when cementing oil and gas wells is long-term zonal isolation, Conkle points out.

Don Conkle, Schlumberger
Click here to enlarge image

“Critical zonal isolation must be achieved to comply not only with regulatory requirements but also to ensure cement integrity while wells are producing,” he says. “New developments toward self-healing cements will definitively have a large impact, especially in environmentally sensitive areas, where venting gas or flowing hydrocarbon through the cement sheath, is an intolerable risk.”

Self-healing or self-repair cements will provide a true long-term zonal isolation, Conkle notes, adding, “Today’s technology for self-healing relies on hydrocarbon presence, but in the future it may rely on water.”

The use of special cement slurries can enable an operator to introduce an aggressive, focused multistage frac program, according to Halliburton’s John A. Ringhisen, technical advisor, Oklahoma City, and Ronald J. Crook, senior technical advisor, Duncan, Okla. Ringhisen and Crook provided written responses to Oil & Gas Journal Technology Forum’s queries.

“In eastern Oklahoma’s Woodford shale play, Newfield Exploration Co. has achieved zonal isolation using foamed cement in a horizontal well section, enabling aggressive, focused multistage fracture treatments,” they wrote. “Conversely, wells cemented with conventional slurries did not exhibit adequate zonal isolation and lost fracture-treatment volume to other stages because of channeling in the cement sheath at the top of the horizontal borehole.”

As of early 2008, operators drilling horizontal Woodford shale wells had cemented 116 horizontal production casing strings with conventional cement slurries and 229 horizontal production casing strings using a cement slurry converted to a stable foam cement slurry by adding nitrogen gas, according to Ringhisen and Crook. Of the 105 wells on which production data are available, wells cemented with foamed cement averaged 28.1% more peak 30-day gas production than conventionally cemented wells did.

Using the ductile, foamed cement increased fracture initiation and successful job placement to more than 96.4% of stage stimulation designs, they wrote. Frac operations in conventionally cemented Woodford wells had been considered successful in 79.9% of the stage stimulation designs.

Sand control

Swelling and sloughing of active, unstable shale can cause gravel pack screen assemblies to become stuck so that part or all of the pay zone cannot be completed, notes Bart Waltman, Halliburton sand control fluids product manager, Houston. Or the screen may be installed, but partial hole collapse may cause the gravel pack to be incomplete, leaving bare screen exposed during production. Resulting problems may not be visible until the producing well starts losing production rate or starts producing sand.

Oil-based drilling and completion fluids can significantly reduce or even eliminate hole stability problems associated with drilling and completing this type of reservoir, Waltman says: “Open hole intervals drilled with oil-based fluids can often be drilled faster with a higher rate of penetration and less rig time. And the oil-based fluids tend to reduce or substantially eliminate shale instability issues that can cause hole restriction or collapse.” However, for reservoirs that require sand control, the oil-based fluid is typically switched to water-based fluid before starting the sand control completion operations.

Waltman describes Halliburton’s recent fluid development combined with special service tool fluid flow capabilities, FlexPac service, which allows the simplification of the process.

“Now the drill-in fluid conditioning procedure used for base screen completions can be combined with the service tool flow path capability and an oil-based drill-in fluid-compatible fluid to enable running screens to planned depth.”

FlexPac service includes coordinated service tools and fluids that enable efficient displacement of oil-based fluid from the openhole pay interval without fluid compatibility upsets or screen plugging. Accordng to Waltman, this provides important benefits:

  • Low skin completions to enable better long-term production.
  • Improved success rate of installing screens to total depth and achieving a complete gravel pack.
  • Facilitated use of oil-based drill-in fluid that can reduce rig time, increase penetration rate, and lower drilling cost.
  • More efficient drill-in fluid displacement.
  • Reduced exposure time of shales to water-based fluid.
  • Reduced hole collapse problems.
  • Maintenance of oil-based fluid wall cake to enable return circulation for gravel packing.
  • No requirement for the mud to be pumped through the screen during the transition process.
  • Lower fluid associated costs due to reduced number of fluids required, improved fluid logistics (reduced rig tankage), decreased contaminated fluid disposal costs, and reduced fluid waste and disposal.

Solids-free lost circulation control

One of the major problems encountered in many operations is excessive fluid loss to the formation. This leakoff and the resulting lost circulation can make it virtually impossible to successfully circulate material into or out of the wellbore. Workovers and completions require, among other things, nondamaging products and systems to control fluid loss and keep fluids in balance, Waltman points out.

A new solids-free, low-viscosity fluid system can be used to help control lost circulation over a broad range of temperatures and permeabilities, according to Waltman: “The service modifies the permeability characteristics of the near-wellbore formation to reduce the relative permeability to aqueous or water-based fluids without impeding the flow of oil or gas through the region.”

This new relative permeability modification (RPM) technology can be used for various lost-circulation applications, Waltman notes:

  • Enabling running screens to depth in the open hole laterals. “With inadequate circulation to remove cuttings and debris, running screens to depth in the open hole laterals can be hindered or blocked by bad hole conditions. In addition, when screens are run to bottom in a poorly conditioned lateral, plugging with drilling residue often results in poor productivity.”
  • Gravel pack completions. “For gravel pack completions, excessive fluid loss and inadequate returns flow can prevent efficient gravel transport and complete packing.The new technology used during hole preparation displacement operations or during pumping of the gravel slurry can increase fluid returns flow to allow complete annular packing.”
  • Additional applications. “RPM technology can be used in almost any situation where limiting fluid losses can simplify and facilitate operational efficiency and reduce damage to well productivity,” e.g., coiled tubing cleanouts, workover operations, post-tubing conveyed perforating fluid loss control, and post-gravel pack fluid loss control. ]