Redefining the stimulation strategy
Acid stimulation has long been considered the most effective way to enhance secondary recovery techniques, including open-hole water injection, that are implemented when the natural forces of pressure support from formation water, or the expansion of dissolved gas, become depleted enough to impair the flow of hydrocarbons. Water-flooding can boost hydrocarbon recovery by as much as 40%, as the high-density water—treated or fresh—is injected into the oil-bearing layers, raising reservoir pressure and displacing the hydrocarbons to adjacent production wells.
These recovery improvements are often short-lived, however, because the water, typically injected in a non-uniform way, cannot flush all the oil out of the pore space, due to the fluids’ immiscibility or rock wettability conditions. Well placement and rock heterogeneity, including the presence of fractures, may cause the water front to bypass part of the reservoir. An estimated 50% to 70% of the oil-in-place is left unrecovered after waterflooding, much of it in the form of small droplets detained within large pore spaces.
Additionally, formation damage, which can occur at any time during the lifetime of a well, reduces near-wellbore permeability and obstructs the normal flow of fluids. This further hinders the water injection process from effectively sweeping oil from the reservoir to produce the field.
It is at that point, the operator performs a matrix stimulation to improve injectivity by pumping acid into the rock, to clean out or bypass deposits that inhibit flow and open new pathways to the reservoir. Historically, these treatments have been performed indiscriminately from the surface, resulting in uneven distribution of the fluid, with some zones being over-stimulated and others not receiving any treatment.
This blind acidizing method presents reservoir management problems for operators, who are left with few options other than to deploy production logging tools in multiple runs downhole, to identify the favored pathways and determine which zones are not being stimulated. The process adds considerable time, cost and logistics to the stimulation operation. It also lacks the real-time capability to monitor and control the flow, when the treatment is being pumped into the rock.
While the complexities of open-hole water injection present field management issues for operators worldwide, the problem is especially prevalent in the Middle East, due to rock type and quality of the carbonate reservoirs.
Confronted with multiple challenges in achieving an efficient, cost-effective, secondary recovery program in a carbonate reservoir, Kuwait Oil Company (KOC) implemented a new stimulation strategy. It uses a real-time, pump-through, downhole flow measurement tool conveyed on coiled tubing (CT) to profile open-hole sections, identify thief and tight zones prior to treatment, and monitor and control proper fluid placement during the pumping stages, all in one run, Fig. 1. The technology’s first application launched an entirely new workflow for KOC, resulting in sustainable injection levels to sweep oil from the reservoir while significantly reducing time and cost.
Open-hole water injection, using seawater, is a frequent method of secondary recovery in the carbonate formations of northern Kuwait. Water is pumped into the injector wells, with the front of the water pushing oil toward the producer well. In this region, however, water breakthrough (in the producer wells) and buildup of calcite and sulfate scales in the near-wellbore area of injectors require the application of routine matrix acidizing treatments, which involve injecting hydrochloric acid, at depth, to create new pathways and bypass the near-wellbore damage.
Even placement and control of stimulation and diverter fluids, along the open-hole sections, is critical for optimizing reservoir pressure sweep efficiency, and for delaying water breakthrough, which occurs when water from the injector well begins producing in the producer well. Accurate and proper placement of stimulation fluids is also essential to effectively remediate formation damage. Inability to properly place these fluids is why the success rate of formation damage interventions has, historically, been relatively low.
IMPLEMENTING A NEW STIMULATION STRATEGY
In a comprehensive study, KOC sidetracked several wells in the region and converted them to horizontal, open-hole water injectors to maintain pressure and sweep oil from the reservoir to produce the field. The operator saw immediate oil production improvement until declining injection rates and rising injection pressures compromised oil recovery. Water breakthrough left a lot of oil behind, and washouts jeopardized the integrity of completions. Logging tools were run downhole to gain an understanding of the inflow profile, a method that only identifies issues prior to initiating the stimulation treatment. After running production logging tools, as well as distributed temperature sensing (DTS), conventional acid stimulation treatments were applied, with marginal results. This required KOC to repeat the treatments with increasing frequency and deploy costly methodologies to maintain necessary production levels.
After attempting to resolve these issues without success, KOC opted to test a stimulation strategy, using a new downhole flow measurement system. It is capable of reducing time and the number of runs into the wellbore, while improving fluid placement and management to achieve a faster, more informed matrix stimulation. Two wells in the Mauddud carbonate reservoir were selected, with total depths ranging from 11,000 ft to 14,000 ft and an open-hole section ranging from 2,500 ft to 2,800 ft. Downhole temperatures were between 140° F and 170° F.
A pre-stimulation profile for one of the wells showed that most of the seawater was being injected at the heel and toe of the well, with nearly 60% of the open-hole section receiving very little or no water at all, Fig. 2. Yet, even after receiving multiple acidizing treatments, using a combination of high-strength acid and non-polymer-based diversion, both wells experienced a decline in productivity over time. The likely cause was that the conventional acid treatment design, which used a specific coverage per foot of open-hole interval and alternating stages of acid and chemical diverter, had been treating the same thief zones at the heel and toe, leaving the middle section unstimulated.
Advances in real-time, downhole flow assessment, combined with CT real-time fiber optics, enabled KOC to change the paradigm by introducing an efficient and cost-effective workflow that provides the ability to assess downhole flow during the intervention. This step-change in flow measurement capability resulted in a treatment execution that delivered sustained production improvements. The treatment targeted the exact thief zones with chemical diverter and stimulated the tight section of the open-hole section with acid.
REAL-TIME DOWNHOLE FLOW MEASUREMENT
Engineered to simultaneously profile horizontal sections, and treat them in a single run with the same BHA, the Schlumberger ACTive Q* CT real-time flow measurement service enables operators to evaluate the flowrate contribution to each interval, and assess zonal coverage during the treatment. By using compatible flow measurement instruments while pumping, the operator can place the fluid more accurately and control where the fluid is going in real time. The operator can take immediate action, such as adjusting pumping schedules for the diversion and subsequent stimulation stages, to optimize the treatment outcome.
This capability eliminates the uncertainties of trial and error, and the need to run time-consuming, costly logging operations. Flow sensors are used to obtain the initial injection profile, replacing DTS, which usually requires long acquisition times in water injectors. Better control of fluid resources reduces the amount of acid needed, a cost-effective alternative to blindly pumping a large amount of acid without knowing where it is going. The service generates actionable, high-quality flow monitoring data that provide the ability to assess how the reservoir is behaving and what is occurring in the wellbore in real time, while the intervention is taking place.
The data are acquired by the ACTive DFLO* CT real-time flow measurement tool, which provides real-time readings of multiple downhole parameters, including pressure, temperature, casing collar locator (CCL) for depth control—all conveyed to the surface through fiber optics installed in the CT pipe. Importantly, the tool helps track the direction that the fluid takes, based on the reservoir’s response to the treatment as it progresses. Pumping rates, injection depth and fluid volumes, based on real-time downhole information, can be adjusted precisely. The tool also profiles flows across producing and injecting intervals to help operators make informed decisions on treatment options.
The new stimulation strategy for the two KOC wells involved isolating both the toe and heel of the wellbore and targeting the middle section with a high-strength acid placed in-between the two extremities of the horizontal section, which required the use of CT, Fig. 3. The BHAs were configured with pressure, temperature and CCL sensors, and the flow monitoring tool, typically comprised of two modules, each, with an array of four flow sensors, all conveyed by a fiber optic-equipped CT unit. In this case, the lower flow monitoring tool module was replaced with an assembly that combined depth correlation modules, using CCL and gamma ray sensors, and high-pressure jetting nozzles to bolster the stimulation treatment, as it was pumped through the CT, so it would penetrate the matrix more effectively.
OPTIMIZING VOLUME AND COVERAGE
The acid treatment design involved pumping a viscoelastic self-diverter acid at the heel of the well, after which CT was run to terminal depth (TD), to place the rest of the treatment at the toe. Similar to a retarded acid, this treatment allows for some stimulation of the formation while facilitating diversion of the flow toward other tight zones. By optimizing the volume and coverage in both sections, the toe and heel of the wellbores could be cleaned while acid stimulated the tight zones at full strength. This was accomplished by moving the CT to the middle section, where it was reciprocated while pumping high-strength acid to open the entire section.
The CT was run in the hole to the end of the production tubing, where depth correlation was performed, and then run in the horizontal open-hole section, eventually reaching TD. During the trip downhole, pressure, temperature and flow readings were monitored closely to identify potential anomalies along the open-hole section. This provided important data regarding the potential of washouts, debris and crossflow, which are especially significant regarding the velocity data provided by the flow measurement tool. The velocities would later be interpreted into volumes and rates, the results of which are influenced by the degree of understanding of the open-hole characteristics and geometry.
After the CT reached TD, the water injection operation began, with the rate and surface pressure kept as steady and close to the nominal values as possible. When the flow had stabilized in the well, the flow sensors were activated. The CT was pulled out of the hole while fluid velocities, pressure and temperature were logged along the entire length of the open-hole section. Additional static flow measurements were recorded from predetermined points downhole.
At the end of the production tubing, when the flow measurement tool was in a controlled environment of known flowrate and cross-section, the flow sensors were calibrated. CT was again run in the hole to TD, to calculate flow velocities along the intake interval, using available caliper data. The flow velocity profiles clearly identified and quantified the intake and tight zones, providing the operator with valuable information to adjust the volumes of both the acid and diverter to be pumped along the open-hole sections. This was an effort to achieve a more targeted formation damage removal and a more uniform injection profile after stimulation.
After the treatment was pumped, water injection was reinitiated to evaluate the effectiveness of the stimulation and obtain new downhole flow distribution data.
IMPROVED INJECTIVITY, FLOW DISTRIBUTION
A post-treatment evaluation showed a marked improvement in both injectivity and flow distribution downhole. For the well presented in Fig. 2, a sustained 100% increase in injection rate was achieved. Using the same surface injection rate, wellhead pressure also dropped from 1,500 psi before the stimulation to nearly 0 psi after the treatment. The same variation was seen in downhole pressure values. The numbers showed that, overall, the treatment improved injectivity in the well, with the injected seawater distributed in a more uniform way along the entire length of the horizontal open-hole interval following stimulation.
The more uniform injection profile achieved by rebalancing the distribution of the injection in the reservoir resulted in several advantages. It generated a more sustainable injectivity increase, with all zones benefitting from the injection, and maintained pressure across the entire reservoir to improve the sweep efficiency of the water. The resulting flow profile, more evenly distributed, also delayed the occurrence of water breakthrough in nearby oil producers, eliminating the need for costly remediation interventions and ensuring more sustained and economical oilfield production. By opening the wells’ middle sections, which had not contributed to the injection previously, KOC achieved a more even downhole flow distribution along the horizontal open-hole interval. This resulted in greater pressure support for the reservoir, with the middle sections of the interval accounting for nearly 40% of the flow after treatment.
The real-time downhole flow service has brought the effectiveness of acid stimulation treatments in Kuwait to a new level of cost efficiency and reliability, expanding the envelope for production enhancement in complex carbonate reservoirs. Injectivity in both wells increased 600%, compared to pre-stimulation levels, saving three days of operational time and considerable cost associated with the deployment of various tools and services and multiple runs downhole. Costs were reduced further by using the same technology to acquire an intake profile and convey the treatment, and by reducing the expected volume of stimulation fluid.
More than nine months after the acidizing treatments, injectivity levels have not declined, with high injection rates and low injection pressures remaining constant. This represents a significant improvement over results from previous interventions, which showed injectivity rates dropping within a few weeks.
The CT real-time flow measurement service has been implemented in other regions of the Middle East and in Central America. 
*Mark of Schlumberger
ACKNOWLEDGEMENT
This article was adapted from SPE/ICoTA paper 184760, which was presented at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, held in Houston, Texas, March 21–22, 2017.
