Summary In 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 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 discuss if 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 real-time readouts of the temperature surveys and an accurate real-time model are needed. With DTS, the real-time readout is a feasible technique 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 describes these techniques, models, and validations using several case histories. In addition, an analysis of matrix treatments using DTS temperature surveys, where available, are presented. The models are used in the analysis to obtain calculated fluid flow distribution. We discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.

Protecting completion and production equipment is of utmost concern during acidizing The higher the temperature, the more difficult it is to protect metal against corrosion, and the required inhibitor loadings increase with temperature, resulting in greater likelihood of formation damage. In addition, the protection times are reduced dramatically, which can potentially limit well stimulation treatments (for example, fluid volumes caused by pump time limitations). These problems become increasingly severe in formations with bottomhole temperatures greater than 250 F (120 C). Even if adequate corrosion protection can be achieved during stimulation, post-treatment production of chlorides associated with the injected HCl-based acids remains a problem. There is increasing concern when the wellbore contains high-alloy metals, such as stainless and duplex steels, which are susceptible to hydrogen embrittlement and chloride stress cracking. When combined with the possibility of erosion corrosion caused by high production rates, acidizing high-pressure, high-temperature (HPHT) wells poses risks. A combination of organic acids (acetic and formic) can be used instead of hydrochloric acid (HCl) to minimize corrosion problems in high-temperature applications. The blends are designed so that the dissolving power is equivalent to HCl with significantly reduced corrosion rates and the absence of Cl- ions. Some of the gelling agents developed for HCl yield higher viscosities in organic acids on an equivalent polymer-loading basis. The end result is an organically based, high-temperature acid system that uses existing technology and is technically and economically more attractive than an HCl-based system. The example application includes the use of an organic acid blend to effectively stimulate the 350 F (175 C) Arun limestone formation in Indonesia. A total of 17 large-scale acid fracs and a similar number of large matrix-acidizing treatments have been performed over the past 3 years. Rheology and corrosion data will be presented with the details of the treatment procedures and production responses. Introduction Corrosion is defined as the deterioration of a substance (usually a metal) caused by a reaction with its environment. The molecules of acids ionize in a water solution to release the hydrogen ion from the acid's constituent elements. The strength of an acid is proportional to the concentration of hydrogen ions present. The attack of acid on metal tubulars manifests itself through the dissociated hydrogen ions of the acid solution, which results in the oxidation and dissolution of iron at the anodic sites on the metal surface with the attendant reduction of hydrogen ions and generation of hydrogen at the cathodic sites. Acid corrosion can be minimized by the use of corrosion inhibitors. The following factors will influence the performance of commonly available inhibitors:–temperature acid strength–contact time–inhibitor concentration–concentration and compatibility of various acid additives Increases in any of these factors, except inhibitor concentration, will increase corrosion rates. Unfortunately, the relationships are not straightforward. For example, increasing the temperature by 50 F from 150 F to 200 F will cause a less proportional increase in corrosion compared to a similar incremental temperature increase from 250 F to 300 F. A 5% increase in HCl concentration from 10% to 15% will not yield the same effect on corrosion as would a similar 5% incremental increase from 15% to 20% HCl. Acid corrosion is also strongly influenced by the chemical composition of the steel. Therefore, metal chemistry is an important factor when acid corrosion of steel is considered. P. 523

The 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 particulate-diversion 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, fluid-efficiency 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 performedbefore diversion,during injection of the diverter,immediately after diverter placement, andfinally 1–2 days later to confirm diverter degradation. The pressure-matching techniques used in this study would not be unique in proppant-fracturing applications; however, the application to matrix stimulation and chemical placement techniques using both pressure matches and injection profile matches are unique and novel processes. Introduction Success of a stimulation or chemical squeeze treatment often depends on complete coverage of all zones. In many cases, placement of the stimulation fluids or squeeze chemicals is just as important as the fluids selected. Unless the zone of interest is extremely thin and/or has no permeability variations, simply pumping the treatment into the formation will not ensure that all of the productive intervals will be treated. The most likely recipient of most of the injected fluids will be the highest-permeability, lowest pressure, or least-damaged intervals. To achieve uniform placement of injected fluids, the original flow distribution across the interval to be treated must be altered to provide generally equal fluid-invasion profiles. The methods used to alter this flow distribution are called diversion methods, since their purpose is to divert the flow of fluid from one portion of the interval being treated to another. Fig. 1 illustrates a successful diversion experiment carried out with two formation cores of different permeability (470 mD and 1.4 Darcy) in a parallel-flow apparatus. Before diversion, the higher-permeability core accepted 75% of the total inflow. After diversion, the inflow was uniformly distributed between the two cores. The diversion method best suited for a particular situation depends on many factors, including the type of well completion, perforation density, casing and cement sheath integrity, and formation characteristics. Selection of the most appropriate diversion method is greatly influenced by the variations in formation permeability along the interval to be treated. Laboratory experiments have shown that the maximum flow contrast (a ratio of injection rates)1 that can be diverted by manipulating rate alone is about 10. With greater permeability contrasts, more aggressive diversion techniques are required. The surest way to uniformly treat the complete interval is with a mechanical-isolation device such as a straddle packer or movable packer/bridge plug assemblies. This approach, however, requires well intervention and is often cost-prohibitive. As a result, various other diversion methods are more commonly used. Diversion methods fall into four general categories:ball sealers,viscous fluids,foam, andparticulate-diverting agents. This paper will focus on one novel, degradable, particulate diverting agent.

The simplifying assumption that limestones essentially have infinite reactivity has been a powerful and useful tool in helping our industry understand and model the acidizing process of carbonate formations. However, over the past few years, considerable work has shown that this assumption need not be used. In fact, use of this assumption can lead to incorrect conclusions regarding optimized acidizing of carbonate formations. This paper builds upon the historical foundation of understanding the acidizing process and brings together the reactivity studies using a number of different reactors to show that carbonates do not have infinite reactivity. It also shows the results of using proper reactivity data and proper reactivity theory for treatment designs.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn matrix acidizing of carbonate reservoirs, the generation of wormholes is a major key to success. Numerous papers have been written that describe the formation and propagation of such wormholes. Generally, these models have been based on sound chemistry and physics. Some of the models have been validated against laboratory experiments that are generally conducted in a linear geometry. However, in order to use the models in the design of matrix acid stimulation treatments, the models need to be validated under radial flow conditions that dominate field treatments.Radial flow, competing wormholes, permeability contrasts, and reservoir height are example parameters that cannot easily be validated in laboratory experiments. Scaling of the models to field conditions might be required. Two types of models have been written for aiding in treatment designs. One model, called a linear-type model, is fully consistent with the decades of linear flow tests conducted in the laboratory. The second model, called a symmetry model, is exceedingly difficult to validate in the laboratory. This paper evaluates both models against treating pressure responses from field treatments.A matrix treatment simulator was used that includes such effects as multiple formation layers with independent formation parameters and allows for modeling zonal coverage. The formation parameters include permeability, porosity, mineralogy, acid reactivity, skin damage, and permeability contrast. The well parameters include height of the layers, wellbore tubulars, friction pressures, etc. This simulator was an ideal framework for evaluating the two acidizing wormhole models. This paper demonstrates the key issues related to the interaction between the wormhole models and zonal coverage.