Successful High-Pressure/High-Temperature Acidizing With In-Situ Crosslinked Acid Diversion

Abstract

This paper describes a very successful acid stimulation treatment performed in AGIP's Trecate-Villafortuna Field. The matrix acidizing treatment used in-situ crosslinked acid (ICA) as the diverting agent. The treatment is unique because it represents the highest temperature application ever attempted for such a system and falls under the definition of high-pressure high-temperature (HPHT). The design process included temperature simulations, detailed laboratory testing, and a review of acid formulations that were used successfully in the Trecate-Villafortuna Field and elsewhere. Temperature simulations indicated that cooldown from the bottomhole temperature (BHT) of 180°C to at least 150°C could be achieved despite the high treating pressures that limited injection rates. Even after cool down, serious concerns about corrosion and the effectiveness of the ICA system still existed. Laboratory support included fluid optimization for high-temperature application of the ICA. The flow tests enabled the selection of the most appropriate base acid systems and demonstrated that the ICA system would indeed function at the predicted high temperatures. Success of the treatment must also be attributed to the operational planning and close attention to experience gained from previous stimulation treatments. The execution of the treatment used all of the components considered to be state-of-the-art in matrix acidizing treatment execution and evaluation: pre stimulation injection tests, spotting of acid with coiled tubing (CT) to help reduce injection pressures and improve zonal coverage, the use of the Maximum Pressure Maximum Rate Diversion Technique (MAPDIR), and real-time treatment pressure monitoring. The paper will present job procedures and a detailed treatment pressure analysis. It will also give details on the changes in injectivity and the Productivity Index (PI) before and after stimulation. Introduction The HPHT Trecate-Villafortuna well discussed in this paper produces oil from a naturally fractured dolomite reservoir at a depth of 6000 m. In this well, a new horizontal 220-m section was drilled and completed as open hole. The goal of the acid treatment was to remove the near-wellbore mud damage and to improve the permeability of the horizontal drain. The high pressure at 6000 m and the bottomhole static temperature (BHST) of 182°C, classify the acid treatment as HPHT. During the treatment design phase, two major issues had to be addressed:Potential problems associated with the HPHT character of the well: high acid-rock reaction rate, cross linking chemistry, and corrosion of tubular goodsProper diversion and optimal zonal coverage of the entire 220-m payzone High-temperature acidizing poses a number of problems during treatment design and execution, which are not normally encountered during treatments at lower temperatures.1,2 The high acid-rock reaction rate requires the use of a retarded acid system to ensure that acid will not all spend on the formation face (compact dissolution) but will penetrate deeper into the formation. Protecting the tubulars against acid corrosion is another serious challenge at high temperatures and requires careful selection of the acid fluids and inhibitor package design. In the following sections of this paper we will discuss these issues in more detail.

Evaluation of A New Liquid Breaker for Polymer-Based In-Situ Gelled Acids

“…In-situ acid systems can be used at HTHP wells. Well designed treatments were successful at temperatures up to 176°F (Buijse et al 2000). Lynn and Nasr-El-Din (2001) examined these acids at high temperatures.…”

Enhancing Geothermal Reservoirs

“…High temperature reduces the efficiency of corrosion inhibitors and increases their cost. Protecting the tubulars against corrosion requires careful selection of acid fluids and inhibitors (Buijse et al, 2000), while cooling the well by injecting a large volume of water preflush may reduce the severity of the problem.…”

Application of Cationic Surfactant-Based Fluids for Acid Diversion

“…Coreflood tests were conducted at 175 F in a linear mode at a constant low flow rate, and the pressure drop across the core was monitored (Buijse et al 2000). It is important to note that coreflood experiments were performed in duplicates, and a new core was used in each experiment.…”