Formation-specific, multifunctional completion fluids helping operators maximize production
By Katie Mazerov, Contributing Editor
Just as no two reservoirs are alike, completion fluids are formation-specific concoctions engineered to provide the proper degree of density and flow characteristics that enable production. Flexible, multifunctional completion fluids, typically brines such as chlorides, bromides and formates, secure the wellbore and enable cleanup of debris or formation solids, such as sand, in the upper completion. They also minimize formation damage as completion systems are run downhole.
As wells have become more challenging, particularly in the high-stakes deepwater sector, completion fluids are being designed to expand their capabilities, performing a multitude of tasks that deliver customized solutions with greater efficiency. Key drivers include a trend toward open-hole completions, the need for more effective well cleanouts and high-pressure, high-temperature (HPHT) requirements. Cost and heightened environmental sensitivity also are motivating efforts to develop fluids and polymers to maximize production, pushing the limits of the Periodic Table and going beyond conventional brine-based solutions.
Whether the objective is an initial well completion or a workover, the fluid selection process is a balancing act that is all about the fluid, the formation and the people, said George King, Distinguished Engineering Advisor for Apache Corp. “The ultimate goal is to control the well. Generally the dynamic barrier we use is fluid as an alternative to mechanical methods, such as snubbing. The main challenge is finding a fluid with sufficient stable density to control or, in the case of a workover, kill the well, and still be able to clean up the fluid and solids to bring the well back online.”
Among the key considerations are the pressure ranges and the formation structure that provides the permeability. Fluid loss control is adjusted with polymers or other fluid-loss control additives to provide enough density to control the formation pressure without creating an overpressured situation where extreme amounts of fluid can be lost to the formation. Clear brines may be used in cases where solid particles are particularly damaging. In cases where excessive fluid loss is a concern, brines with a graded salt or a calcium carbonate fluid can be effective in fluid loss control and easily removed, Mr King explained.
“We worry a lot on the completion side about relative permeability and the effects of clay dispersing and migrating, swelling within the structure of the rock in some cases, and damage from the fluid to the structure of the rock in other cases,” he continued. “Shale formations, for example, have such low permeability, they won’t take much fluid regardless how long it is in the wellbore, so the initial completion fluid may be nothing more than fresh or saltwater. The latter is preferred for long contact periods because it does not disrupt the near-surface clays in shales as much as freshwater.”
In cases where a shale well requires control after it has been fractured, the objective is to avoid damage to the fracture flow capacity by minimizing the loss of liquid and solids into the hydraulic fractures and the natural fractures.
Heavier clear brines have been effective in particle-sensitive formations over the past 20 years, providing control with minimal formation damage in high-pressure wells. “Because many of these brines, especially formates, are so expensive, operators often lease rather than buy them, paying the rental fee and buying the column of brine that is not recovered.” The recovered fluid is returned to the supplier, where it is filtered and leased out for other operations.
Low-pressure formations present a different set of circumstances, especially in producing wells that require complex or time-consuming workovers, Mr King said. “Loading the well with fluid often results in damage to the rock, either through the use of fluid-loss additives or relative permeability effects in the formation from large-volume fluid losses. Often, low-pressure zones take on excessive volumes of fluid that we can never get back, and sometimes the well doesn’t come back either.”
Pressure, fluid sensitivity to the formation, cost and operator preference must be considered, he noted. “Often, there are special circumstances, for example, completing a sour gas well in a sensitive urban or easily disturbed wildlife area. An operator may choose a high-density fluid that provides good control to significantly reduce risk, even it means lowering production by damaging the rock. Using such a fluid may not require as much human monitoring unless the formation is fractured. Lower-density fluids may not create as much damage, but they require considerably more expertise on the rig.”
Sterile, safe environment
The reservoir is the operators’ most important asset, and maximizing productivity is always one of their main drivers. Therefore, the formation-specific nature of designing reservoir or completion fluids means they can’t be mass produced for “cookie-cutter” applications, said Julian Coward, Strategic Business Manager for Baroid, a product service line of Halliburton. “All fluids that come into contact with the reservoir are uniquely customized to improve the reservoir’s ability to produce.”
For Baroid, the process of designing a fluid begins by evaluating and analyzing the unique requirements of each reservoir, where the priority is on protecting the formation from damage or impairment. In the upper completion, which runs from the reservoir back to the surface, cleanup of both the well and the tubulars is a major priority. “The main objectives of an effective cleanup are to provide a sterile and safe environment for running very expensive and complex completion strings. Running the string in a wellbore that has been poorly cleaned or engineered can impede production,” he said.
Typically, reservoir fluids are designed using degradable polymers and acid-soluble materials that allow remediation to the filter cake, if needed, to stimulate productivity. “Fluid innovation comes down to specific well design,” he said. “How the customer is going to design the well is how we customize the fluids. We take a proactive approach to engineering out known undesirables, such as solids invasion, fluid invasion and emulsion blocks, in order to get the best production from the operator’s valuable reserves.”
When it comes to ongoing R&D, completion fluid technology continues to be driven by a need to find new or re-engineer formation-friendly polymers that are stable under extreme conditions. Deepwater is still the fastest growth sector, due to well design complexities. Elevated water depths, high pressures and high temperatures often require use of expensive heavier-density brines, specialized systems, larger volumes of fluid that necessitate better cleanups and more sophisticated completion techniques, Mr Coward noted. “The higher-density brines are not only in short supply, they are considerably more expensive.”
To address that limitation, Baroid is undertaking R&D efforts to develop alternatives to the heaviest types of clear brines readily available, notably zinc bromide, which can’t be used in many regions due to its toxic nature, and cesium formate, which is often cost-prohibitive. “The challenge is that any alternatives must provide the same functionality as clear brines, which are solids-free to avoid damage to the wellbore, impacting productivity.”
Baroid also is currently working with a major operator in deepwater Gulf of Mexico (GOM) to engineer reservoir fluids in excess of 400°F, introducing new formation-friendly polymers that are effective in these high-temperature environments. “There are not a lot of reservoirs at 400°F, but as operators continue to venture into longer, deeper and hotter formations, they definitely need that technology and capability,” Mr Coward said. “This has involved a major redesign, not just tweaking existing technology, as current industry standards struggle to be effective at those elevated temperatures.”
As the operator’s technical challenges continue to be ever more demanding, Baroid is heavily focused on R&D initiatives that include cost-effective additives and designs for niche applications, such as enhancing filter cake breaker capability, novel perforation pills for cased-hole applications and low-density reservoir fluids for heavily depleted zones, he said.
For sand control and gravel-pack completions, operators are looking for simplicity on top of flexible multifunctions. “As well temperatures and pressures increase and fluid mixes become more difficult and expensive for operators, we are focusing on simplifying the management of fluids by developing almost boutique solutions,” said Jamie Pollard, Vice President, Sand Management Services for Schlumberger. “The importance of completions fluids is significantly higher in the open-hole environment, which has grown significantly in the last five years, both on land and offshore, even in traditional cased-hole markets.”
Historically, clear brines primarily have been used, especially in cased-hole completions, because the perforations are susceptible to damage from solids. With the paradigm shifting, the term “completion fluid,” which the industry tends to define as clear brines, is being expanded to “fluids for completions,” explained Charles Svoboda, Vice President, Wellbore Productivity for M-I SWACO, a Schlumberger company. “Conventional wells that require sand control to prevent the production of formation solids have traditionally been a cased-hole market, and the completion fluids we’ve used were clear brines, generally chloride- or bromide-based. As technology has improved and we’re able to perform open-hole completions in more challenging reservoirs, we are utilizing a number of fluids that are not clear brines.”
Driving this trend is the need for fluids that are heavy enough to provide wellbore stability and well control but do not invade the formation. Schlumberger has developed a portfolio of water-based alternatives to clear brines, as drill-in fluids for open-hole sections, while using a clear fluid for the cased-hole portion. Clear fluids are often used to clean the open-hole section and remove the filter cake prior to production.
A displacement system displaces drilling mud with brine and integrates mechanics, specialized cleaning tools, chemistry, including environmentally friendly solutions, and hydraulics to clean up the cased-hole section above the open hole. The displacement system also can be used to remove mechanical debris to prepare the well for production, Mr Svoboda noted.
The MUDSOLV NG Integrated Filter-Cake Removal Service for open-hole completions, introduced in 2013, provides analytical tools to optimize removal of the residue, or filter cake, on the open-hole section just before the well begins production. This ensures a continuous process to reduce time and intervention costs, especially for the deepwater environment, Mr Svoboda said. “The objective is to thoroughly dissolve the filter cake in a controlled manner as soon as practical after completing the well.”
In July 2013, Schlumberger used a low-density 9.98 lb/gal calcium carbonate brine fluid to maximize production in the first horizontal open-hole, gravel-pack well in a deepwater field in Ghana with reactive shale, carbonate scaling and a relatively narrow window density. The completion design included sand control screens, a reservoir drill-in fluid (RDF) and gravel-pack sand.
The system maintained proper rheology for hole cleaning and inhibited shale and scale inhibition, preventing formation damage. The fluid was modified to a solid-free RDF by removing the weight materials to prevent screen damage and minimize any losses in the event the filter cake was disturbed. The RDF system provided a stable wellbore and allowed the well to be completed on schedule with no nonproductive time. The RDF filter cake was removed as part of the completion process.
Compatibility issues with brines in challenging environments, such as HPHT, also are pushing the industry to seek new solutions. “While most completions are still done in a brine environment, we are looking at ways of using oil-based fluids throughout the completion to eliminate steps, such as converting an oil-wet environment to a water-wet environment when a well has been drilled with an oil-based mud, or using weighted, oil-based swellable fluids to activate packers for zonal isolation,” Mr Svoboda said.
Historically, the inability to generate higher density without solids has been the limiting factor in using oil-based fluids. “The size, amount and concentration of solids work against us in completions, so we are looking at developing micronized materials, which the drilling industry has used for many years,” he said.
Safe and versatile
Weatherford also is targeting its R&D efforts to the offshore sector, where higher temperatures and pressures, cost and the need to comply with often stringent environmental regulations are driving innovation, says Luc Leoni, Region Manager, Drilling Fluids and Engineering Chemistry for Weatherford. “The requirements for completion fluids are much higher than for drilling fluids, in part because completion fluid stays in the well anywhere from a few hours to several days or weeks, depending on whether we are cleaning up the well, removing the filter cake, running a gravel-pack operation or need to maintain pressure to run completion tools,” he said. The inability of weight materials, such as barite, to dissolve requires the use of other solutions, such as calcium-carbonate fluids, to maintain stability.
Weatherford’s high-concentrate, low-corrosion, environmentally friendly fluid provides an alternative to zinc or formate salts. The phosphate-based fluid is commercially available up to 15.2 lb/gal and can be made heavier upon request. It is more cost-effective in the density range than calcium or formate-based brines, which often have difficulty achieving a workable formulation, Mr Leoni explained. “The fluid is mild enough that it can be handled safely in the field yet meets the requirements for completion brines, especially in environments where high pressures require high-density solutions.”
Weatherford is planning to launch field trials this year for a strontium carbonate-based reservoir drill-in fluid that can achieve a density of 16 lb/gal, and up to 17 or 18 lb/gal with heavy brines. “Strontium carbonate, which uses less volume than calcium carbonate, is suitable for high-pressure, deepwater fields and land operations where we need high-density fluids, such as HPHT wells,” he said. The use of strontium also provides more flexibility. “In many cases, we can use seawater initially, then add strontium carbonate, instead of starting out with a heavy brine.”
Soluble additives and polymers that are compatible with completion brines but also provide adequate functionalities such as lubricity, also are in the R&D pipeline. “Completion brine needs to be very clear, so we don’t want to cause any haziness or polymer debris in the brine that can lead to potential formation damage,” Mr Leoni said. “Completion brines, from low to high densities and from sodium chloride to formates, have very different chemistries. What is compatible in one brine may not be compatible in another. This is a major challenge for brine lubricants.”
The industry is also striving to develop environmentally friendly solutions, especially related to additives and surfactants that enhance wellbore productivity. “Except for the North Sea, we don’t have a very well established system for defining what is green,” he noted. “We know what is greener, but not what is green.”
Operators often prefer to use biopolymers, rather than synthetic polymers, because they are easier to clean up and less damaging to the formation. “However, synthetics perform better at higher temperatures; biopolymers often degrade when temperatures reach 250°F to 300°F,” Mr Leoni said. “The objective is to use a good viscosifier without leaving debris in the wellbore after cleanup, so the polymer needs to be flexible and multifunctional.
“The other challenge with completion fluids is that when we pump fluids downhole, some fluid is always released to the formation due to the overbalance,” he continued. “To address that issue, we are looking at developing fluid systems with additives built in so that when fluid is released, it favors production in terms of wet-ability to promote easier flowback when the well is brought online.”
Baker Hughes is working on developing fluid designs and additives, including viscosifiers, surfactant packages and corrosion-inhibitors, that can tolerate downhole temperatures up to 450° or 500°F, said Clark Harrison, Product Line Manager, Completion Fluids, for Baker Hughes. “Reservoir drill-in fluids, displacement technologies, completion brines and additives all come into play as we move into these high-temperature applications, including open-hole gravel pack operations.”
Higher-density brines enhanced with additives supplied by the Baker Hughes Pressure Pumping segment are effective in deepwater fracturing operations. “Because downhole pressures are greater in these applications, our fracturing department developed a new system based in a higher-density sodium bromide brine,” Mr Harrison explained. “Using sodium bromide brine not only provides the required density for well control, it also reduces the hydraulic horsepower required at the surface for pumping.” The chloride-free fluid also eliminates the risk of chloride stress-corrosion cracking.
Earlier this year, a custom-engineered sodium bromide fracturing fluid was applied in a deepwater GOM well to achieve a six-zone frac-and-pack completion in one trip. The fluid and breaker package were designed to tolerate the well conditions and provide stability for two hours while the pumping operation was implemented.
High-temperature displacements have been achieved by combining displacement chemicals, cleanup tools and engineering software, an integrated methodology that has been especially effective when displacing oil-based mud to a clean completion brine. “Conventional cleaning chemicals can degrade at higher temperatures, especially when pumping very deep wells that take longer to displace,” he explained.”
Spacer designs must take into consideration the degradation and thermal thinning effects of the polymers used for viscosity. “If the viscosity significantly drops because of the higher temperature, the transition spacer can no longer ‘push’ the synthetic/oil-based mud (OBM) out of the hole,” Mr Harrison explained. “The spacer will become intermingled with the drilling fluid and strung out, resulting in a failed displacement. If any mud residue remains after a displacement, components such as barite and clays from the OBM can cause formation damage.”
Fluid applications are tailored to the way a well is being completed, he added. “For example, a fracturing operation will fracture past any formation damage the drilling fluid and filter cake may have caused. However, for open-hole completions, we use products in the drill-in fluid that are soluble so that when those components are laid down as part of the filter cake, the filter cake can be easily removed when necessary.”
A significant challenge is that water-soluble viscosifiers, typically natural polymers, often degrade above 275°F. Synthetic polymers can withstand higher temperatures and remain stable but can make the filter cakes much more difficult to remove. “We work our way our backwards,” Mr Harrison said. “There is a significant amount of research, testing and planning that goes into each fluid design to maximize production and ensure a smooth operation.”
For mature wells that require remediation due to declining production, Baker Hughes applies its mesophase technology, a blend of surfactant packages that can solubilize oil. “The advantage of solubilizing oil, rather than dispersing it, is that the oil is no longer available to emulsify with water. For example, if a well has been damaged by the formation of emulsions, the mesophase treatment will solubilize the oil from the emulsion, freeing the water phase and thereby mobilizing the solids. Once this process occurs, the emulsions that were causing the damage are removed so production can increase. With this technology, we have revived wells as old as 57 years and brought them back on production,” Mr Harrison said. “The technology of solubilizing oil is also used as a filter-cake breaker for open-hole completions, synthetic/OBM displacements and pre-flush spacers for cementing.”
MUDSOLV NG is a mark of M-I-SWACO, a Schlumberger company.