In matrix treatments, optimum placement of the injected fluids is essential. Over the years, several diversion techniques have been applied to obtain a desired fluid distribution. The latest developments in the application of distributed temperature sensing (DTS) during matrix treatments to monitor temperature profiles along the wellbore in real time show that fluid distribution can be quantified. This paper discusses the application of DTS to quantify the effectiveness of diversion agents. Quantification of fluid distribution makes it possible to determine the flow distribution both before and after a diverter stage so that the diversion effect can be evaluated. Knowledge of the diverter effect will lead to better understanding of the diversion process and subsequently to optimization of future treatment designs. Ultimately, use of real-time quantification of the effect of diversion will lead to the development of real-time optimization itself. In real-time optimization, the results of a diverter stage will be used to adjust the next diverter stage to optimize placement. The post-treatment analysis of the temperature profiles showed that flow distribution can be quantified both before and after a diverter stage. Based on the observations, the decision was made to develop a diagnostics tool that can be used in real time and will enable real-time quantification. The novel approach of using the diagnostics tool in combination with DTS during matrix acid treatments will help to further optimize diversion treatments. This optimization is both an optimization during the treatment and an optimization of diverter stages in future treatments. Introduction Optimum fluid placement and complete zonal coverage are essential in a successful matrix acid treatment. This is especially true for long intervals with high degrees of heterogeneity. Without effective fluid diversion, the injected fluids will follow the path of least resistance and will only stimulate strongly depleted zones or the zones with the highest permeability or the least damage. Fluid diversion methods are introduced to divert the flow away from this path of least resistance (Hill 1994; Glasbergen and Buijse 2006). The most commonly used diversion methods are (a) foams, (b) balls, (c) particulates, and (d) gels, or (e) maximizing the injection rates. It is outside the scope of this paper to discuss these diversion methods, which have been discussed extensively in earlier publications (Parlar et al. 1995; Rossen 1994; Erbstoesser 1980; Nitters and Davies 1989; Glasbergen et al. 2006; Lietard 1997; Paccaloni 1995). Evaluating fluid placement and the effectiveness of fluid diversion has long been recognized as a challenge in the industry. Various techniques have been developed and utilized to determine fluid placement. Example methods include (a) evaluating injection rates along with surface or bottomhole pressures (McLeod and Coulter 1969; Paccaloni 1979; Prouvost and Economides 1989), (b) production logging tools (Glasbergen et al. 2006), (c) radioactive tracers, (d) simulations, and (e) distributed temperature sensing (DTS). In this paper we will limit discussion to the use of DTS. Distributed Temperature Sensing (DTS) Oilfield applications using distributed wellbore temperature surveys have been in practice since the early 1950s (Nowak 1953; Kunz and Tixier 1955). Distributed temperature sensing (DTS) is a valuable tool used to understand the dynamics of oil and gas production and injection rates. Some of the earliest work with this technology was to quantify production profiles on producing wells. This is achieved by monitoring the temperature variations caused by flow or injection rates at the reservoir entry points.

Hydrofluoric (HF) acidizing in the Monterey shale has had a long history of success, dating back to a case study performed in 1999 (Rowe et al. 2004). A proper acid-design program is critical to the success of these types of treatments. However, proper placement technique carries the same importance as the acid design. This paper will review a placement technique that not only provided proper placement but also reduced placement time significantly. Monterey shale intervals commonly reach 1,500 to 2,000 ft in vertical height. To further complicate downhole work, intervals are not homogeneous; there are differences in natural fractures, permeability, and porosity. The goal of matrixacidizing treatments is to place the acid below fracture pressures. Formation differences, including degree of damage, can limit injection rates and increase the pump time necessary to place the acid. Physical well conditions, such as the cement bond, create other challenges to overcome. Placement time for these acid treatments often takes several days to complete and can require multiple service providers, such as production rigs, downhole tools, remedial cement work, and coiled tubing (CT) units. With consideration to these issues, several questions arise, such as how can the entire interval be successfully acidized, the number of required services reduced, and placement time decreased. Using the new placement technique, the entire planned completion interval can be perforated in a rigless manner, acid equipment can be moved in that is capable of producing sufficient injection rates to exceed the formation’s ability to accept fluid below the fracture gradient, and real-time downhole monitoring equipment is installed to provide the operator and service provider adequate data to make decisions and adjust as necessary while pumping.

Successful acid treatment depends largely on the method used to place the acid. Water-injection wells are commonly treated using coiled tubing (CT) and a high-pressure nozzle to increase the well's injection rate. This paper focuses on the comparison of two types of high-pressure nozzles, as used in a slotted-liner cleanout in a sandstone formation. A majority of the diversion techniques available are classified as mechanical, such as straddle packers, opposing cup tools, particulates, and perforation ball sealers. In addition, the industry uses a variety of chemical diverters, such as gelled acids and foamed acid. These options might work fine in perforated and cemented casing, but there are not many effective options available with respect to matrix acidizing of long, uncemented slotted liners in sandstone formations. CT acid jobs have typically used nozzles, such as the fixed nozzle, rotating-jet nozzle, and the fluid oscillating (FO) nozzle. However, the newest innovation in fluid-oscillating tools is the fluid-oscillating tuned frequency and amplitude (FOTFA) nozzle, which is more efficient than the previous fluid oscillating tuned frequency (FOTF) nozzles. This paper presents case histories that compare the results of acid jobs using rotating jet nozzles and the latest FOTFA nozzles. Four analogous water-injection wells were chosen for the trial and were acid stimulated using CT. Two wells were acidized using a rotating nozzle and the other two with the FOTFA nozzle. The wells are in the same field and were treated using the same acid design and pumping procedures.

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After successful production from a few wells in a California field, two development/appraisal wells were drilled targeting the southwest flank of the structure. Based on experience with the offsets, it was expected that this sandstone formation would be fracture stimulated to mitigate formation damage. Most of the wells in California have intervals ranging from 1,500 gross ft to ~600 net ft. Fracture stimulation or matrix acidizing are common stimulation techniques used on these types of wells. Fracture stimulation was attempted because of very low permeability but was not successful. On the first well, several attempts were made to establish fracture initiation in different intervals; however, on each attempt, the fracturing pressure encountered was too high to safely continue the job. A fracture gradient of more than 1.1 psi/ft was estimated. After 20 days of unsuccessful attempts, the operator ceased fracture stimulation of the well, which was nearing the point of abandonment because producing oil or gas did not seem economically viable at this point. After carefully studying the matrix rock, a gas-assisted perforating process followed by foamed matrix acidizing was recommended as an economical solution to produce the wells. This gas-assisted perforating process uses an extreme overbalanced (EOB) condition by using energized gas to simultaneously perforate and stimulate a well in a single intervention. During an EOB perforating application, wellbore pressures will exceed the fracture gradient for several seconds to minutes while injecting wellbore and tubing fluids at high rates. This paper presents a case study of two unconventional tight-gas condensate wells where using a gas-assisted perforating process followed by foamed acidizing provided successful stimulation. The design considerations, stimulation technique, and job details are discussed.