Ordinary acid fracturing treatments cannot deliver consistent production results in low-pressure carbonate reservoirs. The reservoir pressure is not sufficient to flow back the large volume of treating fluids from the formation after the treatment, thus minimizing the benefits of performed acid fracturing. The use of foamed acid fracturing fluids will provide additional energy that will help to enhance flowback and push treating fluids out from the reservoir during post-fracturing flowback operation. There are two types of gaseous phase that are commonly used to foam the fluids for stimulation treatments: nitrogen (N2) and carbon dioxide (CO2). N2 is an inert gas; it is widely available and therefore the most frequently used. CO2 is more soluble in water than N2; therefore, more CO2 is required to saturate the liquid and create the foam. CO2 has more expansion during flowback, which aids in total fluid recovery. Additionally, the solubilized portion of CO2 reduces the interfacial tension of the fracturing fluid. A deep high-temperature carbonate reservoir typically requires acid fracturing treatment to produce at economic gas rates. When reservoir pressure declines over time, foamed acid fracturing treatment becomes the preferred stimulation option. Both types of the gaseous phase show good success. The multiple case studies suggest that foamed acid fracturing resulted in easier flowback initiation and better well productivity compared to regular acid fracturing. Moreover, CO2-based foams provided better results compared to N2 foams, especially in horizontal wells completed with multiple acid fracturing stages within the same reservoir. The specific fracturing fluid was deployed to use CO2 foam in the wells with high bottomhole temperatures up to 300°F. The innovative CO2 foam chemistry enables formulating non-crosslinked gels that deliver viscosity equal to or better than the industry-standard foams of low-pH guar crosslinked fracturing fluids. This fluid delivers those results at significantly lower polymer loadings and with a reduced number of additives, thus improving the operational aspect and increasing well productivity. Another noticed benefit of foamed acid fracturing with CO2 is the easier achievement of higher foam quality at bottomhole conditions. N2 is pumped in its gaseous phase and requires specific pumping units with limited pressure and rate capacity. In contrast, CO2 is pumped in its liquid phase through the common fracturing pumping units; therefore, a significantly higher pumping rate of the gaseous phase can be achieved with minimum additional equipment.
The Orenburg oil, gas and condensate field (OOGCF) is one of the largest fields in the Volgo-Urals region of Russia. It is characterized by complex formation lithology, underlying water, low bottomhole temperature and significant reservoir depletion making successful matrix acidizing particularly challenging. Existing wellbore equipment prohibits the use of inflatable packers. Therefore only chemical diverters can be used for treatments. Thorough engineering and previous acidizing experience in this region lead teams to select the following technologies to account for all challenges in stimulation on OOGCF: Viscoelastic self-diverting acid (VSDA). Based on viscoelastic surfactant, VSDA initially has low viscosity. However, while the acid spends, the fluid viscosity increases, redirecting flow to less permeable zones. After the treatment, viscous VSDA losses its viscosity when it comes in contact with hydrocarbons and/or solvent pumped in the preflush stage. Absence of polymers in VSDA eliminates risk of formation damage.Selective diverter for temporarily blocking water-producing zones. This water-based fluid with viscoelastic surfactant initially has high viscosity. During matrix acidizing treatment, the selective diverter is injected into all zones. Its viscosity sharply drops in the hydrocarbon-saturated zones while maintaining stability in water-saturated intervals, thus preventing acid injection in undesirable zones.Foam diverter allows foam to be generated in the matrix and temporarily plug the pore spaces. This causes temporary plugging of the acid-etched channels and allows unstimulated zones to be treated. The main advantage of foam diversion is fast and efficient cleanup, which is especially important for depleted formations.Highly retarded emulsified acid helps create wormholes while treating long intervals with low pumping rate through coiled tubing (CT).CT placement with pumping foam diverter through CT and HCl through CT - Tubing annulus simultaneously to block known thief zones. Up to date 3 stimulation treatments were successfully performed with average incremental gas production of 61% that could not be achieved before on this field. A combination of all solutions and technologies mentioned above allowed to address all challenges related to matrix acidizing on OOGCF field.
Gas-bearing carbonate reservoirs in moderate to low permeability reservoirs have been targets for acid fracturing treatments in the Middle East. These formations typically exhibit high temperatures, medium to low porosity, and high heterogeneity in terms of lithology and reservoir properties. The heterogeneity dictates completion strategy, with multiple perforated intervals across large gross height in vertical wells with subsequent acid fracturing treatments that aim to cover all perforated intervals in a single treatment. But due to differences in lithology, intervals with high dolomite content are less likely to receive stimulation due to higher stress and reduced acid reactivity. Temperature logs performed on many wells after conventional acid fracturing treatments showed that these perforated intervals accept only a small amount of treating fluids, compared to intervals perforated in clean limestone. An efficient, non-damaging, near-wellbore diverter is required to efficient treat all intervals and improve productivity in such wells. The objective is to stimulate all existed intervals in a single pumping operation, regardless of reservoir heterogeneity, by using degradable diverting materials to temporarily isolate created fractures and redirect the flow to untreated areas. The diversion material used is a composite pill comprising a proprietary blend of degradable fibers and multimodal particles, designed to provide an effective isolation plug at the face of the reservoir in a consistent manner. Fibers are added to ensure the integrity of the diversion pills during delivery and to enhance the bridging mechanism. The use of fibers allows minimizing required diverter volume to few barrels and engineered multimodal diverting materials allow having very strong diversion pressure with small amount of the material. The process increases operational efficiency, well productivity, and estimated ultimate recovery. The materials used to provide temporary isolation have proprietary formulation that degrades within hours or days, depending on bottomhole temperature, with no need of intervention or pumping chemicals to break down the system. Two pilot treatments with degradable diverter were conducted in high temperature high pressure carbonate reservoirs. Extensive measures were undertaken to evaluate the treatments, including pressure analysis, separator tests, temperature logs, production log (PLT), pressure build up (PBU), and nodal analysis. Overall, the measurents and analysis of the treatments proved the efficiency of the degradable diverter for vertical wells: sharp pressure increase up to 1,600 psi when pills arrived at perforation; cooldown effects in all intervals on the post-fracturing temperature logs ensuring uniform distribution of the acid; high flowback gas rates, substantially higher than those of offset wells treated without the diverter; fracture response and signature observed on PBU data; PLT contribution from most of the perforated intervals confirming that treatments penetrated all intervals of interest; and nodal analysis with good production match showed long etched fracture half-length - a preferred fracture geometry for tight reservoirs.
The Volga-Urals basin is one of the largest oil-producing regions in western Russia. The most prolific wells are producing from Devonian formations characterized by light crude oil with high bubblepoint pressure. Today, most of the Devonian reservoirs are depleted and produce at bottomhole flowing pressure below bubblepoint pressure, which yields multiphase and non-Darcy flow in hydraulic fractures, drastically decreasing production. As a result, conventional hydraulic fracturing treatments are less effective. To regain fracturing treatment efficiency, the restrictions to hydrocarbon flow inside the fracture must be minimized. To account for this, a new method of fracture conductivity generation was introduced. Channel fracturing creates open pathways inside the fracture, enabling infinite fracture conductivity. Channels are created by discontinuous proppant feeding at surface into viscous fracturing fluid. Dissolvable fibers are added to the slurry to separate proppant structures and prevent them from settling during treatment. Proppant structures act as bridges inside fractures; voids between them are essentially stable channels connected along the entire length of the fracture. While channel fracturing has already been implemented successfully in many places around the world, the fracturing conditions of Volga-Urals Devonian formations were still new for this technology. The Volga-Urals region is well known for high tectonic stresses and low fracturing-fluid efficiency. While channel fracturing treatments are being designed and pumped in a regime without tip-screenout (TSO) in other locations, channel fracturing treatments in Devonian formations often showed significant TSO. Production analyses showed consistent productivity increases, and in most cases, 2 folds higher compared with offset wells where conventional fracturing technology was used. After the success of the pilot campaign, proppant flowback was resolved by incorporating a rod-shaped proppant as a tail-in stage of channel fracturing schedules. The nonspherical shape of the proppant increases internal friction between the particles and mechanically holds them in place. In addition to improving proppant flowback control, the combination of technologies maximized conductivity of the near-wellbore area which connects channels and the wellbore. The success of more than 30 of such fracturing treatments expanded the pool of candidates for channel fracturing with rod-shaped proppant to meet the challenges of similar complex geological conditions.
Carbonate reservoirs host a significant amount of hydrocarbon reserves in the Middle East and worldwide. In matrix acidizing stimulation, hydrochloric acid (HCl) is commonly injected into the well at pressures less than fracturing pressure to dissolve the carbonate rock and create high-conductivity channels, known as wormholes. Wormholes propagate through the damaged near-wellbore zone connecting the well with the reservoir. In this work, we aim to study the effects of pre-existing fractures on wormhole development. Matrix acidizing processes were reproduced in controlled laboratory experiments where a 15% HCl solution was injected into a borehole drilled in a carbonate block sample containing pre-existing fractures, allowing the acid to penetrate radially into the rock sample. The experiment was conducted inside a polyaxial load frame to accommodate large block samples (20×16×16 in.). Prior to acid injection, the block was fully saturated with water and taken to 2,000-psi pore pressure and 4,000-psi confining stress to simulate downhole conditions. To evaluate the created wormholes, the tested block was cut open along the fractures followed by X-ray CT scanning of selected zones. Here we report experimental results for matrix stimulation of one Indiana limestone block containing a series of parallel pre-existing fractures. Acid was injected at a constant rate through the 1-in. diameter borehole containing an 8-in.-long openhole section in the center of the block. Although the acid injection pressure was maintained below the pressure required to open the fractures, acid breakthrough was found to be governed by the pre-existing fractures. Indeed, unlike similar radial acidizing experiments in intact blocks, there were no indications of wormholes exiting the outer faces of the block. Moreover, the post-test evaluation of the central fracture along the openhole section clearly revealed the wormholes that etched the fracture faces. However, a closer look into the stimulated openhole section showed that the wormholes initiated in other directions inside the matrix as well. An X-ray CT scan of a 4-in. diameter cored borehole regions allowed us to compare the density and characteristics of the wormhole growth along the fracture and into the matrix. Although radial acidizing experiments describe more closely real conditions of matrix acidizing, few cases have been published, particularly for large-block experiments. The large-scale block experiments presented in this study provide new insights on the impact of pre-existing fractures on wormholing mechanisms.
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