Halliburton Energy Services’ Harvey J. Fitzpatrick, Jr. shows how wellbore stimulation fluids can increase production.
Fig. 1—Example of acid-etching properties of SandStim service. The service provides the performance of traditional HF acid blends but in a simpler and safer formulation. Images from Halliburton.
Mature fields present significant opportunities for increased production with lower overall expenditures. Opportunities for enhancing production in existing fields follow the oil industry dictum, “the best place to find oil is where you have already found it.”
Many wells have production rates that are limited by near-wellbore permeability damage or restrictions to inflow caused by flow-impeding solids accumulation. These wells can be identified as “under performers”—wells whose production doesn’t live up to their potential or whose production has fallen below what their reservoir pressure potential would indicate. Consider the opportunity offered by using remedial near-wellbore stimulation solutions to provide immediate economic impact by enhancing production from mature assets. Mature fields hold greater than 2.4 trillion bbl of known oil reserves and, currently, more than 70% of the world’s oil and gas production comes from mature fields.
Halliburton’s acidizing technology developments were commercialized as two integrated stimulation system platforms. Sandstone 2000 acidizing service fluid systems and the engineered treatment design approach used with them combined a consistent method of design with fluid systems specifically tailored to sandstone reservoir characteristics and targeted to their damage mechanisms. The Carbonate 20/20 acidizing service engineered workflow and fluid system series provided the tools to design treatments focused on carbonate reservoir rocks and flow potential characteristics for optimum results. The Carbonate 20/20 service used reservoir understanding and design tools focused on the reservoir rock characteristics to select from a suite of carbonate acidizing systems and engineered treatment processes. These technologies combined the stimulation knowledge obtained by chemical technology development and innovation in fluids formulation with a better understanding of reservoir mineralogy and flow characteristics parameters to provide a step change in acid stimulation production improvement reliability.
Fig. 2—Example of extensive matrix damage as a result of fluorosilicate precipitation that can be caused by conventional HF acid blends. SandStim service can remove damage in the formation with less risk of further damage or rock deconsolidation.
Many areas hold opportunities for near-term uplift in mature production if promising candidates are identified and the treatment design is suited to the well’s stimulation requirements. Often, under-performing wells can be selected, but developing a stimulation treatment for them with a high assurance of success might be more challenging. More often, crucial reservoir mineralogy information required for the stimulation design is not available or is costly to obtain. Additionally, for sandstone reservoirs with moderate carbonate or highly sensitive clay content, successful acid stimulations are at greater risk. For wells with more extreme reservoir conditions (high-pressure/high-temperature), risk-weighted economics for the stimulation candidate might not be favorable because of concerns about corrosion to downhole equipment. High-temperature reservoirs or expensive metallurgies can contribute to unacceptable corrosion rates with conventional acid stimulation fluids. In this type of well, conventional hydrochloric- (HCl-) based or organic acid stimulation fluid treatments can provide a potential for gain but that might not outweigh the risk of a lost well or the cost of an unpredictable result.
Fortunately, new chemical stimulation technology advances offer better alternatives for wells with mineralogy or corrosion characteristics unsuitable for acid stimulation and for wells with insufficient reservoir mineralogy information necessary to determine a reliable acid stimulation treatment design.
Chemical stimulation technology
Fig. 3—Example core samples showing treatments with KelaStim service (left) and acetic acid (right) at 350°F. KelaStim service has less risk of formation damage than acid-blend fluids.
Chelant-based stimulation fluids from Halliburton, such as SandStim for sandstone reservoirs and KelaStim for carbonate reservoirs, constitute the next step in chemical stimulation. Chelant technology enables more reliable sustained production results but requires less complexity in fluid selection and treatment design compared to acid-based fluids (Figure 1). Technology built into Halliburton’s chelant stimulation fluids enables optimized treatments for a broad range of reservoir and well characteristics. Treatment design is less complex because chelant technology accommodates a broad range of mineralogy. The risk of collateral damage from spent fluid is significantly lower than from acid-based treatments (Figure 2). Successful stimulation is achieved more reliably. Hazards associated with reservoir damage, tubular and well equipment corrosion, and health, safety, and environment (HSE) concerns can be significantly reduced. Successful results are obtained with greater reliability. Chelant stimulation fluid systems provide the following benefits:
Treatment design is simplified. Chelant stimulation technology helps reduce risks of concurrent treatment damage with solubility control for spent-treatment fluid.
Potential damage can be minimized when stimulating formations of uncertain mineralogy.
Heterogeneous or layered formations can be stimulated without the risk of precipitating dissolved ions or chelant-metal ion complex, with less risk of sludge formation and rock deconsolidation.
Less risk exists of deconsolidating friable formations; these fluids can provide deeper penetration of live stimulation fluid in carbonate reservoirs.
Their superior complexing capacity helps reduce post-stimulation damage from spent fluid precipitates.
They can be used in wells with higher carbonate concentrations; it is recommended to use them with sandstone formations over 5% soluble carbonate content.
- These fluids can be used in a wide temperature range (120-350°F for SandStim service; 120-400°F for KelaStim service).
- Typically, they are less corrosive than traditional HCl and hydrofluoric (HF) acid blends.
- Their inherently safer chemistry has reduced HSE risks compared to traditional HCl and HF acid blends.
SandStim and KelaStim services have shown better sustained production improvement in mature wells compared to convention acid treatments in the same well or offset wells.
SandStim case study
An operator in the Gulf of Mexico (GoM) recently required removing barium sulfate scale and formation damage from a sandstone reservoir. Halliburton conducted laboratory tests to evaluate using a combination of the new SandStim service chelant-HF acid stimulation system placed with coiled tubing and the Pulsonix TFA acoustic stimulation service to help maximize the effectiveness of stimulation for this gravel pack completion. To be successful, the treatment was required to mitigate damage from both scale and fines damage at the gravel pack to reservoir interface while reducing or eliminating the risk of precipitation damage from spent fluid remaining in the low-pressure reservoir.
The Halliburton consulting and project management team managed logistics, personnel, and technology requirements for the operator. Pulsonix TFA service, Halliburton’s fluidic oscillator stimulation technology, was selected to enhance the efficiency of contact of the treatment with the damaging materials in the gravel pack and well-reservoir interface. Pulsonix service was incorporated to place 100 gal/ft of a SandStim service fluid blend across a 167ft interval that has been in production since 1996.
The SandStim service chelant/HF-acid blend has a relatively high pH compared with more commonly used acid blends. To help reduce hazards associated with tubular and well component corrosion, Halliburton’s production enhancement technology team created a corrosion inhibition testing protocol, and together with their chemical stimulation specialists, developed and tested an optimized additives package for the treatment. The well tubulars were hydroblasted to remove barium sulfate scale. Solids were not observed in high concentrations in the returns flow; however, upon draining the return fluids tank, measurements showed that 67cu ft of solids had been removed from the internal diameter of the wellbore tubulars.
The vessel support teams from Port Fourchon, Louisiana, and New Iberia, Louisiana, loaded Halliburton’s marine vessel, Stim Star III, with approximately 72,000 gal of stimulation fluid. The vessel arrived eight hours ahead of schedule. After a safety briefing, the crew rigged up and placed the treatment using Halliburton coiled tubing with the Pulsonix TFA service.
InSite Anywhere fracturing and stimulation services software enabled multiple stakeholders to remotely view the pumping operations in real time and allowed the chemical stimulation technology team to monitor the treatment progress from the Houston Technology Center.
Using all Halliburton equipment, operating efficiency throughout 36 hours of constant pumping was 100%, and the crew set a record for stimulation pumping time in the GoM.
Because of low bottomhole pressure, the well was jetted with nitrogen to enhance flowback and fluid recovery. The cleanup flowback recovered almost 100% of the treating fluids, from which samples were taken for analysis at Halliburton’s Houston Technology Center.
The operator then placed the well on the platform gas lift. Over the next several days, with an optimized choke size and gas lift injection rate, post-treatment production more than tripled the pre-treatment hydrocarbon rates.
During the entire offshore operation, no Bureau of Safety and Environmental Enforcement (BSEE) incidents of noncompliance, recordable incidents, or accidents occurred.
KelaStim service in Angola
In the offshore waters of Angola, a principal operator was losing production from one of its best wells. Well history showed various degrees of scale and halite buildup, causing a significant decrease in production. Five previous HCl-/acetic-acid blend treatments had provided only short-term increases, failing to sustain higher levels of production.
The operator engaged Halliburton to provide a stimulation design that would deliver a sustained production increase. The treatment for the tubular scaling and near-wellbore area damage mitigation had to be tailored for the removal of halite, iron carbonate, and calcium carbonate scale over a 2400ft (731m) perforated interval, with bottomhole temperatures exceeding 300°F (149°C) and a low bottomhole pressure. Because of the low reservoir pressure, slow and inefficient treatment fluid recovery had been experienced after previous treatments.
Testing on area cores revealed HCl-/acetic-acid blends to be highly reactive on the very heterogeneous lithology under reservoir conditions. Core testing indicated this acid system caused a considerable level of rock deconsolidation and non-uniform stimulation of the core flow characteristic. A different approach was necessary to optimize the treatment design for more sustained higher production by reducing fines release from deconsolidation, by providing more uniform penetration of stimulated flow area around the wellbore, and by reducing concurrent precipitation damage from unrecovered treatment fluids.
The treated cores were submitted to computer tomography (CT) analysis of the stimulated flow patterns after core flow testing to help visualize how the different treatments manifested improved flow. CT analysis helped confirm that the conventionally treated cores experienced isolated areas of high dissolution. Whereas, the chelant treatment provided uniformly distributed enhanced flow capacity throughout the core volume with little or no deconsolidation (Figure 3). Following this and other rigorous qualification testing of the treatment formulation on the reservoir cores, Halliburton proposed using the new KelaStim service. Compared to other treatments tested, KelaStim service delivered improved overall stimulation results with a range of core samples at different depths and varying mineral composition. The recommended treatment design incorporated KelaStim service combined with BioVert biodegradable diverting material to provide more uniform stimulation across the entire perforated interval.
Pre-job analysis, evaluation, and design of the treatment solution developed from accurate formation data and core analysis coupled with the technical expertise and synergy of all participants proved successful in the treatment results. The treatment was executed safely and according to design. After stimulating the well with three stages of KelaStim service separated by two stages of BioVert diverter material, production was monitored for 90 days to evaluate the long-term response.
The enhanced production realized with the KelaStim service proved to be significantly better than with previous treatments. Average daily production increased 35% during the 90 days, adding over 31,000 bo to production and US$2.6 million in additional revenue to the operator’s bottom line.
Compared with previous acid stimulations, KelaStim service delivered four noteworthy technical benefits: (1) improved iron stabilization from the dissolved scale and tubing pickle to help minimize collateral treatment damage; (2) increased depth of stimulation and reduced risk of rock deconsolidation, for a more sustained stimulation effect; (3) uniform rock matrix stimulation; and (4) lower corrosion potential and greater temperature stability.
To date, the well continues to produce at a stimulated rate, and the operator is screening candidates for treatment using KelaStim service in other wells in the area.
Harvey J. Fitzpatrick Jr. is production enhancement frac/acid product manager for Halliburton Energy Services in Houston. His 36 years of well construction and completion experience span positions including field engineering, on-site supervision, sales, global technology advisor and management. He is inventor or co-inventor on 14 patents and is author or co-author on 33 technical papers or journal articles and has served on a number of industry technical program committees. His BSChE degree is from Tulane University.