fax 01-972-952-9435. AbstractIn matrix treatments, placement of the injected fluids is essential for success. Over the years, several diversion and placement techniques have been applied to obtain a desired fluid distribution. Real-time evaluation of a treatment was limited to observing injection pressures or bottomhole pressures. These measured pressures provided some information on the diversion process. The application of distributed temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. In this paper, we will discuss whether DTS can also be used to quantify the fluid distribution during a matrix treatment.For the real-time quantification of the fluid distribution during a matrix treatment from temperature surveys, both realtime read outs of the temperature surveys and an accurate realtime model are needed. With DTS, the real-time read out is a feasible technique that has been developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and near-wellbore thermal model is available that runs in real time. This paper will describe these techniques and models and validations using several case histories.In addition, an analysis of matrix treatments using DTS temperature surveys, where available, will be presented. The models will be used in the analysis to obtain calculated fluid flow distribution. We will discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we will describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe success of all oilfield chemical treatments is dependent upon fluid placement efficiency. In acid-stimulation treatments, the acid should be placed so that all potentially productive intervals accept a sufficient portion of the total acid volume. The same is true for scale-inhibitor squeeze treatments. It is critical for the inhibitor to be distributed as uniformly as possible over the interval of interest.Various diversion techniques are available to assist in alteration of the injection profile during matrix treatments. Likewise, several computer design programs are available to advise on appropriate diversion techniques and allow numerical simulation of the diversion process and efficiency. Rarely are placement models validated in the field.Recently, a joint project was initiated to develop a novel fluid-diversion process. This project resulted in a particulatediversion agent that has several advantages over traditional particulate diverters. Advantages include little or no environmental impact, negligible solubility at surface conditions, controlled permeability of the filter cake or perforation pack, upper temperature limit significantly higher than traditional diverting agents (excluding salt), compatibility with nearly all treatment fluids, diverter degradation at bottomhole conditions to eliminate post-treatment removal, and excellent regained permeability.The chemical development is not the only unique and novel aspect of this joint development. An extensive field trial was conducted, incorporating multiple step-rate tests, fluidefficiency tests, treatment-pressure matching, pressure-buildup tests, temperature surveys, and injection profiles. These tests were performed in a 226ºF sandstone reservoir at approximately 11,900 ft MD. Testing was performed (1) before diversion, (2) during injection of the diverter, (3) immediately after diverter placement, and (4) finally 1-2 days later to confirm diverter degradation. The pressure-matching techniques used in this study would not be unique in proppantfracturing applications; however, the application to matrix stimulation and chemical placement techniques using both pressure matches and injection profile matches are unique and novel processes.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe high levels of carbon dioxide and low levels of hydrogen sulfide content of some deep and high temperature gas producers contributed in the requirement to complete these wells using super Cr-13 tubings. Due to the low permeability of the formation and the associated formation damage issues, acid fracturing treatments were required to optimize the productivity of these wells. This paper describes the selection, optimization and long term comparative evaluation of the gelled and in-situ crosslinked HCl/formic acid systems used this type of wells. The high temperatures encountered in deep wells and the susceptibility of super Cr-13 to severe corrosion in high concentration HCl systems used for stimulation purposes added one additional difficulty to the acid stimulation process. To overcome these problems, extensive experimental and field studies were performed to select an acid system to enhance the productivity of these wells.Core flood tests performed with HCl/formic acid systems showed their ability to create deep wormholes in tight carbonate cores; however the corrosiveness of these systems at downhole conditions could be severe if the correct type and concentration of corrosion inhibitor is not used. In general, for the HCl/formic acid systems at downhole conditions (275°F) it was found that high concentrations of corrosion inhibitors are required to protect the super Cr-13 completions.Based on lab tests study acid stimulations were performed, the flow back fluid was recovered and analyzed to observe the corrosion problems and to optimize the corrosion inhibitor.In all the cases the wells responded very well to the acid stimulation and the completion integrity was not compromised in a short or long term. The paper also shows for the first time a comparative long term well response to the acid stimulation of the two acid systems used in the area, showing the better performance of the in-situ crosslinked HCl/formic system over the gelled HCl/formic system.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper discusses the development of a unique in-situ crosslinkable acid system that uses a blend of HCl/formic acid as the base acid and a synthetic polymer gelling agent. The ability to in-situ crosslink an organic acid blend is novel. In addition, an unexpected result of the fluid development was the discovery of its unique rheological properties.Historically, both gelled and in-situ crosslinked acids have been used for fluid loss control during fracture acidizing and for diversion in matrix treatments in carbonate formations. Various synthetic polymers are used to gel the acid. Past research indicates that ~20 cp base gel viscosity is required as the first step in fluid loss control. In-situ crosslinking allows very high viscosities to be generated as the acid spends. The crosslinked gel creates a permeability barrier and subsequent fluid stages are diverted to other sections of the zone. When the acid fully spends, the gel breaks, giving a low viscosity fluid.HCl is the most common base acid used for carbonate stimulation. Combinations of HCl and organic acids have been used because of their high dissolving power and relatively low rates of corrosion at elevated temperatures. In extreme cases, combinations of organic acids are used. While HCl/formic acid blends have been utilized in the past, the unique rheological properties of these blends have not been fully explored.The chemistry and rheology of gelled and in-situ crosslinked HCl/formic acid blends equivalent to 28% HCl will be described and compared with traditional gelled acid and in-situ crosslinked acid.
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