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Intervention Work Flow Improves Injection Coverage in Tight Carbonate Reservoirs

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The complete paper discusses an advanced matrix-stimulation work flow that brings reliability and flexibility to the acidizing of tight carbonate water injectors and has delivered injectivity improvements tight carbonate onshore reservoirs in the Middle East. The work flow leverages real-time downhole measurements and the presence of fiber optics in coiled tubing (CT) for telemetry, and relies on a high-pressure jetting tool, controlled with the help of real-time downhole pressure data, to enhance penetration of acid into the targeted intervals.

Introduction

Effective and long-term matrix stimulation of water-injector wells completed across tight carbonate reservoirs presents a significant challenge in the Middle East. Local practices for matrix stimulation of openhole horizontal carbonate water injectors consist of spotting hydrochloric acid treatment by CT along the uncased well section, using a specific fluid dosage per unit length of the pay zone. Thus far, that approach has delivered inconsistent results in wells completed across tight carbonate rock, most often leading to a rapid decline in injection rates following the treatment.

An alternative work flow leverages distributed temperature sensing (DTS) to evaluate the original water-injection coverage across the reservoir. Each section benefits from a customized treatment that increases injectivity and improves uniformity of injection. A high-pressure jetting tool, controlled with the help of real-time downhole pressure data, is key to this work flow because it enhances penetration of acid into the targeted intervals. The engineered work flow has delivered injectivity improvements of nearly 8,000 B/D in the intervened wells, with the DTS survey confirming significant gains in injection coverage along the openhole section.

The complete paper is organized into three sections—matrix stimulation challenges, proposed solution, and case studies.

Matrix-Stimulation Challenges

Unsuccessful acidizing treatments in carbonate formations usually have a common denominator: poor zonal coverage of the pumped stimulation chemicals. In water-injector wells, efficient reservoir sweep relies on understanding the optimal distribution of the stimulation fluid to maximize the water-injection capacity of the well.

Understanding heterogeneity is fundamental for successful water injection in a carbonate reservoir. The presence of a dominant zone, also called the thief zone, is one of the most-obvious manifestations of heterogeneity, usually pointing to a layer with higher permeability than the average reservoir permeability. This heterogeneity leads to nonuniform injection profiles. Consequently, reservoir sweep by water becomes inefficient, leaving significant residual oil behind, risking creation of unwanted pressure differentials in the reservoir and leading to early water breakthrough in nearby producer wells. Fig. 1 shows the downhole intake profile for one water injector well from Field B. A nonuniform distribution of injection water across the uncased horizontal section is featured clearly, with almost all injected fluid going through the middle section [10,886 to 11,480 ft measured depth (MD)], leaving almost 75% of the open hole bypassed. The matrix-stimulation approach should be rethought to address the presence of thief zones.

Fig. 1—Example of downhole intake profile from water-injector well from Field B.

 

Acidizing efficiency is highly dependent on several factors, the most relevant being rock lithology, acid type, bottomhole temperature (BHT), and injection rate. Because CT is the preferred conveyance method to place the stimulation fluids in these tight carbonate water-­injector wells, alternatives to mitigate flow-rate limitations inherent to the selected CT pipe should be considered carefully.

Although fluid conveyance by CT tends to favor a deeper and more-­homogeneous fluid placement across the openhole horizontal section, the presence of ­dominant zones makes this method insufficient by itself, because pumped fluid will always follow the path of least resistance. Complementary placement techniques must be implemented to minimize fluid leakoff into thief zones. Increasing fluid velocity to generate dynamic diversion is one of the preferred alternatives to improve effective fluid placement by CT, with high-pressure jetting and nitrifying stimulation systems being the most-common techniques.

Dual injection by simultaneous pumping through the CT and the CT annulus is another dynamic diversion practice. This technique requires other factors, such as additional pumping equipment, higher fluid volumes, and CT-pressure collapse limitations, to be taken into account.

Chemical diversion is also widely used to foster uniform fluid placement. However, the effectiveness of this technique relies on understanding the location of the high- and low-intake zones before and throughout the stimulation treatment to enable informed adjustments about the suitable location and volume of the diverters.

Depth correlation has always been considered a challenge in CT interventions. Conventional practices that rely on surface devices to measure the length of CT pipe deployed in the well fall short regarding actual tool depth, with errors as high as 0.3% being accepted as common. Standard downhole tools for depth correlation, including memory logging or tubing end locators, require either additional runs or specific well configuration. Particularly in openhole horizontal wells, depth control is of the utmost importance for accurate placement of stimulation fluids into the specific target zones.

The uncertainty and often limited knowledge of dynamic downhole parameters throughout the stimulation operation may lead to a significant impairment of treatment effectiveness. The most-common factors are nonoptimal implementation of the dynamic diversion techniques, overly conservative margins between fracturing pressure and actual injection pressure, lack of awareness of potential sticking events, excessive or insufficient volume of chemical diverters, and improper differential pressure across the jetting nozzle.

Proposed Solution

The enhanced intervention work flow relies on CT equipped with fiber optics to take full advantage of DTS and real-time downhole point measurements. The methodology that forms the basis for this work flow was developed previously and has been customized for tight carbonate water-injector wells and the use of high-pressure jetting to enhance acid penetration into the targeted intervals. An overview of the work flow is illustrated in Fig. 2. The complete paper presents a ­detailed description of the work flow.

Fig. 2—Advanced intervention work flow for matrix stimulation in tight carbonate water-injector wells.

Case Studies

The complete paper presents two case studies. The reservoirs present calcite as the dominant mineralogy with minor amounts of dolomite and clays. Average permeability ranges from 0.5 to 10 md, bottomhole pressure (BHP) reaches 6,000 psi, and BHT ranges from 140 to 265°F. The water injector wells are completed with 3½-in. tubing followed by 7-in. casing, then a 6-in. openhole horizontal section intended to maximize reservoir contact with lateral lengths between 2,000 to 5,000 ft MD. Each case study includes the candidate overview and discussion of the intervention strategy and stimulation approach; well schematics and graphic representations of well deviation, lithology, porosity, and permeability; water injection history; pre- and post-stimulation DTS evaluation; and pre- and post-stimulation injectivity indices.

Conclusions

  • Matrix-stimulation challenges in tight carbonate openhole water-injector wells cannot be properly addressed through the conventional CT approach or local practices. Implementation of an enhanced CT intervention work flow is essential.
  • The engineered work flow has delivered injectivity improvements of nearly 8,000 B/D from the first two intervened wells, with DTS surveys providing identification of high- and low-intake zones and also confirming significant gains in injection coverage along the openhole section.
  • Injection parameters have sustained very good rates after several months, providing significantly better results than those obtained with previous methods.
  • Using the full array of downhole parameters not only yields unprecedented injection coverage in complex reservoirs, but also eliminates uncertainties associated with wellbore conditions.
  • Real-time downhole measurements play a fundamental role in the controlled implementation of the selected dynamic and chemical diversion techniques.
  • CT downhole telemetry also eliminates uncertainties associated with wellbore conditions and high-pressure jetting nozzle performance while keeping injection pressure below the fracturing gradient.
  • Potential improvements to the existing intervention work flow might consider an additional DTS assessment after the initial stimulation stage for early identification of the effectiveness of the ongoing placement technique.
  • Another potential improvement is to incorporate a CT real-time downhole flow measurement tool within the work flow.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199290, “Advanced Intervention Work Flow Brings High-Pressure Jetting to New Heights of Effectiveness and Enables Unprecedented Injection Coverage in Tight Carbonate Reservoirs,” by Samy Mohamed Abdelrehim, Daniel Gutierrez, and Sameer Punnapala, SPE, ADNOC, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19–21 February. The paper has not been peer reviewed.

Intervention Work Flow Improves Injection Coverage in Tight Carbonate Reservoirs

01 June 2020

Volume: 72 | Issue: 6

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