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New Acidizing Method Improves Stimulation in Deep, High-Temperature Offshore Well

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The complete paper discusses a method of stimulating deep, high-temperature offshore wells by combining an efficient single-phase retarded acid (SPRA) system and an engineered, degradable, large-sized particulate and fiber-laden diverter (LPFD). The method was introduced in a well in the Arabian Gulf, where it helped the operator achieve effective, uniform stimulation.

Introduction

Treatment of deep, high-temperature carbonate reservoirs such as those in the Arabian Gulf presents a series of complex and related challenges to achieve effective and uniform stimulation. Elevated temperatures and heterogeneous formations in these reservoirs require robust treatment fluids that can withstand the harsh environment to achieve good reservoir contact with an acid system along the entire interval of interest.

Emulsified acids have been the preferred stimulation choice of major operators in this region because of these acids’ superior corrosion inhibition and deeper penetration into the reservoir. However, using emulsified acid adds to the complexity of the stimulation operation by contributing to higher friction pressures, limiting pump rates, and requiring elaborate mixing procedures that constrain offshore rig-based interventions. Operators are searching for simplified acid systems that can deliver friction pressure similar to that of unmodified hydrochloric acid (HCl) and reservoir contact performance equivalent to that of emulsified acid. Arabian Gulf operators also seek a robust diverter that can withstand high differential pressure at high temperature, enabling efficient treatment coverage of all perforated intervals.

Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to effectively plug the leakoff zones. To address the challenges, an SPRA and a new degradable LPFD system were introduced to conduct a matrix-stimulation treatment featuring efficient contact with the reservoir, safe corrosion inhibition, and effective diversion in a well with a 320°F bottomhole static temperature and a heterogeneous environment with a permeability contrast of more than 100. The SPRA was a 15% HCl-based acid system.

The fluid delivered friction pressures similar to those of unmodified 15% HCl and wormholing performance equivalent to that of emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was greater than 1,000 psi in approximately 60 minutes. After the second stage of acid, the pressure drop was close to 1,000 psi in approximately 30 minutes, achieving an approximately 1,000‑psi increase of injection pressure across the perforations. Additionally, using the LPFD system reduced the footprint in offshore operations, simplified materials handling, and delivered the most efficient diversion performance in bullhead operations compared with that of other diverters.

Overview and Laboratory Qualification of SPRA and the LPFD

The complete paper presents detailed overviews and descriptions of laboratory qualification of the featured SPRA and LPFD approaches. The SPRA overview focuses on conductive channels, including wormholes, and the influence of fluids and injection rates on the dissolution of these channels. These effects can be replicated in the laboratory in cylindrical cores using a coreflow experiment.

An SPRA that was successfully introduced to field-scale applications in Kazakhstan demonstrated a marked improvement over emulsified acid in both wellsite delivery and downhole performance. While previous studies had been limited to wells of moderate temperature, the coreflow experiments for this case study were performed at 325°F. The experiments were performed using a Chandler formation response tester. In each test, the backpressure was held at 1,200 psi to reduce or eliminate the effects of CO2 bubbles. The cores used in the experiments were composed of Indiana limestone or Silurian dolomite and have a 1-in. diameter and a 6-in. length. The brine permeability of the cores ranged from 2 to 10 md for Indiana limestone and 40 to 180 md for Silurian dolomite. Permeability measurements were obtained using 2% potassium chloride brine at the experimental temperature.

The results in Indiana limestone showed that the SPRA is as efficient at penetrating the reservoir as the emulsified acid at most injection rates. In some cases, the SPRA is more efficient than an emulsified acid when injected into Silurian dolomite. The complete paper explains the process for the laboratory qualification of the SPRA.

The complete paper also presents an overview and outlines the laboratory qualification process for the new LPFD, which was created to increase acidizing treatment efficiency and performance in wells with challenging conditions such as high-permeability contrasts resulting from large fractures, vugs, or voids from previous acid treatments.

The LPFD is a blend of multimodal fully degradable particulates and degradable fiber. The particulates are ­larger than conventional diverters for enhanced bridging performance. The largest particulates bridge in a fracture, void, or similar near-wellbore matrix feature, while the smaller particulates accumulate in interstitial spaces to reduce the permeability of the diverter pack. Fibers assist both in bridging and in transport of the particulates downhole without dispersion.

This engineered diverter can plug fractures of up to 12 mm in width and requires a smaller volume to generate the same diversion pressure if measured by the surface pressure change. Preparation and deployment of the diversion pill is easier.

The deployment method was developed to overcome the challenge of pumping large particulates through a conventional positive displacement pump. A high-pressure injector eliminates the issue of moving large particulates through the small gap between the valve and the seat. By eliminating the need for dedicated pumping equipment, the overall footprint at the wellsite is reduced. Additionally, the injector enables the delivery of a highly concentrated pill to the formation and decreases the total amount of diverter pumped without compromising diversion performance.

Laboratory testing and qualification of the LPFD was focused on two areas: determining bridging capabilities of the LPFD and evaluating the length of time the material would persist in the formation at various temperatures before degradation.

Case Study, Arabian Gulf: Matrix Stimulation With SPRA and LPFD

The exploration gas well was completed with a 3½-in. testing string equipped with memory gauges and 4½-in. production liner. Two perforated intervals of 60 ft, each near 16,000-ft measured depth, were placed in a naturally fractured dolomite/limestone formation. The bottomhole temperature was approximately 320°F, and the permeability contrast between the most- and least-permeable zones exceeded a ratio of 120.

In previous acid treatments in nearby wells using conventional diverter materials (ball sealers, crosslinked gels, and gelled acid), leakoff zones along the target interval were difficult to block, indicating that more-aggressive diversion methods would be needed to improve wellbore coverage of the main treatment fluid. The desired treatment for the well included 171 bbl of SPRA split into two stages separated by a small pill of LPFD.

Job Design and Execution

The complete paper presents a detailed description of the modular offshore stimulation system, job design, and execution. The stimulation treatment consisted of two acidizing stages of SPRA separated by one diversion stage. The volume of the HCl acid in the SPRA stages was equivalent to the dosage used for emulsified acid in previous operations. The stimulation treatment was pumped per the schedule, and the bottomhole pressure was recorded through a memory pressure gauge installed in the testing string. When pressure-gauge data were recovered on surface, a more-complete evaluation of the effect of the SPRA and LPFD was conducted. After the SPRA reached the formation, the bottomhole pressure decreased from 12,800 to 11,650 psi during the first acidizing stage and from 12,520 to 11,510 psi during the second stage. Conversely, after the LPFD reached the perforations, bottomhole pressure increased from 11,550 to 12,520 psi, indicating the successful blockage of higher-permeability zones and a redistribution in the flow of treatment fluids to lower-permeability zones (Fig. 1).

Fig. 1—Job-acquisition parameters during the matrix-stimulation treatment. The bottomhole pumping schedule (colored rectangles) is superimposed on the bottomhole pressure.

Conclusions

  • Deep, high-temperature carbonate reservoirs remain challenging for production and stimulation engineers. Finding appropriate and cost-effective solutions to improve stimulation treatments in these wells enables improved operational efficiency and greater recovery of target fluids.
  • An engineered, integrated approach can achieve effective treatment of increasingly challenging offshore carbonate wells.
  • The paper demonstrated that such formations can be treated successfully using a combination of the following:
    • An SPRA fluid to maximize reservoir contact
    • A degradable LPFD system to maximize wellbore coverage
    • A modular offshore stimulation vessel to boost operational efficiency and logistics
  • These methods represent an evolution of current practices and can be considered for effective stimulation in challenging carbonate formations.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196281, “Acidizing Done Right in Hot Offshore Wells: Case Study,” by Max Nikolaev, SPE, Bulat Kamaletdinov, and Nestor Molero, SPE, Schlumberger, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed.

New Acidizing Method Improves Stimulation in Deep, High-Temperature Offshore Well

01 June 2020

Volume: 72 | Issue: 6

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