The effects of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture, both in the main flow direction along the fracture, and in the fluid loss direction. In our tests, the injection rate into the fracture is much higher than in many previous tests, and the fluid loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids---an acid viscosified with polymer, an emulsified acid system, and an acid viscosified with surfactants---at elevated temperatures of 200ºF and 275ºF. The acid fracture conductivity apparatus is similar to a standard API fracture conductivity cell, but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long cores allow for better control of leakoff as the acid creates wormholes into the core samples. In these tests, acid was pumped through the fracture for contact times ranging from 15 to 60 minutes. After the fracture surfaces were carefully characterized with a surface profilometer, the fracture conductivity was measured at increments of closure stress, up to a maximum closure stress of 6,000 psi. In this paper, we present the results obtained from a series of experiments with these fluids using Indiana limestone and dolomite core samples. Among the findings: Introduction Acid fracturing is a well stimulation process in which acid dissolution along the face of the hydraulically induced fracture is expected to create lasting conductivity after fracture closure. However, conductivity after fracture closure requires that the fracture face is non-uniformly etched by the acid while the strength of the rock is still maintained at high levels to withstand the closure stress. At low closure stress, the etched pattern of the fracture face should have a dominant influence on the resulting fracture conductivity as long as the strength of the rock can withstand the load. As the closure stress is increased, surface features along the fracture faces may be crushed and the fracture conductivity is more dependent on the rock strength than on the initial etching pattern. The success of the acid fracturing process depends highly on the resulting fracture conductivity which is very difficult to predict because it inherently depends on a stochastic process and is affected by a wide range of parameters. Most predictions of conductivity are made with the empirical correlation developed by Nierode and Kruk.1 This correlation was based on experiments using 1 inch diameter by 2 to 3 inch long fractured cores, with no fluid loss through the rock samples. The acid fluxes through the fracture in these experiments were much lower than expected in a field fracture. While there have been several other experimental studies done2–5, they were either done at conditions that did not scale to field conditions or did not consider rock weakening or the etching pattern on resulting fracture conductivity while the effect of only a few parameters were studied in a limited number of experiments.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe effects of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture, both in the main flow direction along the fracture, and in the fluid loss direction. In our tests, the injection rate into the fracture is much higher than in many previous tests, and the fluid loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids-an acid viscosified with polymer, an emulsified acid system, and an acid viscosified with surfactants-at elevated temperatures of 200ºF and 275ºF. The acid fracture conductivity apparatus is similar to a standard API fracture conductivity cell, but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long cores allow for better control of leakoff as the acid creates wormholes into the core samples.In these tests, acid was pumped through the fracture for contact times ranging from 15 to 60 minutes. After the fracture surfaces were carefully characterized with a surface profilometer, the fracture conductivity was measured at increments of closure stress, up to a maximum closure stress of 6,000 psi.In this paper, we present the results obtained from a series of experiments with these fluids using Indiana limestone and dolomite core samples. Among the findings:1. The fracture conductivity created did not show a general increase with acid contact time, and in fact decreased at higher contact times with some fluid systems. This suggests that optimal times of acid exposure in acid fracturing treatments exist.2. There were large differences in the conductivity created with the three acid systems tested. At 200ºF, the acids viscosified with polymer or surfactants created much higher conductivity than the emulsified acid system.3. The laboratory-scale acid fracture conductivities measured in these experiments do not agree with the predictions of the Nierode-Kruk correlation.
The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is: Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole. Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.
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