Abstract

Carbonate reservoirs are quite tolerant to problems originated by poor stimulation practices. Therefore, acidizing of carbonate formations has been overlooked in many aspects. The objective of this paper is to provide a comprehensive reference material that will help the matrix stimulation designers to quantify formation damage, select optimum fluids for carbonate reservoirs, design and place proper treatment, hence stimulate the carbonate reservoirs in engineered way.

Well operations can damage the formation, from the moment the first drill bit penetrates a permeable formation to the end of its productive life of it. Most types of damage reduce the formation's natural permeability. Identifying the causes of formation damage and how to prevent it have been the subjects of much research, but well operations still continue to cause some degree of damage to the formation in the near-wellbore region. Formation damage has a dramatic, adverse effect on the flow of hydrocarbons into the wellbore, because of plugging or partial plugging of perforations, or plugging of the rock structure by debris from the well and from well operations.

Stimulation design for horizontal wells and surprises in some field results indicated the need for systematic analysis of stimulation process in ADCO fields. Therefore, an applied study has been conducted to address the issues related to carbonate stimulation and set field procedures, best practices for the carbonate reservoir stimulation. Reservoir characterization part of the project included sampling of representative cores from the producing and injection formations in all fields. A total of 287 core samples have been collected. Thin section, acid solubility, iron content, X- Ray Diffraction (XRD) and Scanning Electron Microscope (SEM) analysis have been performed on these samples. Existing acid recipes checked and validated against mineralogical composition, acid solubility, and iron content of particular layers and new recipes prescribed accordingly. A detailed questionnaire sent to major oil companies and service providers. Replies processed and findings of the project have been documented as Best Practices.

Introduction

Carbonate rocks dissolve readily in acid. This chemical action is the basis for most of the modern treatment fluids that are used to remove formation damage and increase reservoir permeability, and hence halt or reduce declining production. The well stimulations have been performed using treatments ranging from simply pumping hydrochloric acid to very advanced new technologies that use viscoelastic surfactant-based treatment fluids. The process for identifying the causes of formation damages, removing or by passing it has been detailed in following sections.

What's the damage?

The reservoir zone where permeability has been affected by formation damage is referred as skin. The extent of this permeability reduction depends on the amount of damage and the depth to which it occurs. Mud and mud filtrate can cause pore-throat plugging (Figure 1), either during drilling, for example, when it is pushed ahead of cement. Unfiltered fluids transported during well killing, clay swelling, or debris from completions and sand-consolidating material during production can also plug the formation. The action of the drill bit itself can physically alter the pore structure in the near wellbore, and adverse fluid-to-fluid chemical reactions can lead to emulsion-water block and inorganic scaling, particularly in enhanced recovery situations. Table 1 shows a summary of the scale of formation damage attributable to various well operations.

What's the damage?

The reservoir zone where permeability has been affected by formation damage is referred as skin. The extent of this permeability reduction depends on the amount of damage and the depth to which it occurs. Mud and mud filtrate can cause pore-throat plugging (Figure 1), either during drilling, for example, when it is pushed ahead of cement. Unfiltered fluids transported during well killing, clay swelling, or debris from completions and sand-consolidating material during production can also plug the formation. The action of the drill bit itself can physically alter the pore structure in the near wellbore, and adverse fluid-to-fluid chemical reactions can lead to emulsion-water block and inorganic scaling, particularly in enhanced recovery situations. Table 1 shows a summary of the scale of formation damage attributable to various well operations.

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