REMOVING OF FORMATION DAMAGE AND ENHANCEMENT OF FORMATION PRODUCTIVITY USING ENVIRONMENTALLY FRIENDLY CHEMICALS
Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid, organic acids, or mixtures of these acids are typically used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks including high and uncontrolled reaction rate and corrosion to well tubulars, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at high temperatures. Hydrochloric acid (HCl) and its based fluids have a major drawback in stimulating shallow (low fracture gradient) formations as they may cause face dissolution (formation surface washout) if injected at low rates. The objective of stimulation of sandstone reservoirs is to remove the damage caused to the production zone during drilling or completion operations. Many problems may occur during sandstone acidizing with Hydrochloric/Hydrofluoric acids (HCl/HF) mud acid. Among those problems: decomposition of clays in HCl acids, precipitation of fluosilicates, the presence of carbonate can cause the precipitation of calcium fluorides, silica-gel filming, colloidal silica-gel precipitation, and mixing between various stages of the treatment. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact.
Glutamic acid diacetic acid (GLDA) a newly developed environmentally friendly chelate was examined as stand-alone stimulation fluid in deep oil and gas wells. In this study we used GLDA to stimulate carbonate cores (calcite and dolomite). GLDA was also used to stimulate and remove the damage from different sandstone cores containing different compositions of clay minerals. Carbonate cores (calcite and dolomite) of 6 and 20 in. length and 1.5 in. diameter were used in the coreflood experiments. Coreflood experiments were run at temperatures ranging from 180 to 300oF. Ethylene diamine tetra acetic acid (EDTA), hydroxyl ethylethylene diaminetriacetic acid (HEDTA), and GLDA were used to stimulate and remove the damage from different sandstone cores at high temperatures. X-ray Computed Topography (CT) scans were used to determine the effectiveness of these fluids in stimulation calcite and dolomite cores and
removing the damage from sandstone cores. The sandstone cores used in this study contain from 1 to 18 wt% illite (swellable and migratable clay mineral).
GLDA was found to be highly effective in creating wormholes over a wide range of pH (1.7- 13) in calcite cores. Increasing temperature enhanced the reaction rate, more calcite was dissolved, and larger wormholes were formed for different pH with smaller volumes of GLDA solutions. GLDA has a prolonged activity and leads to a decreased surface spending resulting in face dissolution and therefore acts deeper in the formation. In addition, GLDA was very effective in creating wormholes in the dolomite core as it is a good chelate for magnesium. Coreflood experiments showed that at high pH values (pH =11) GLDA, HEDTA, and EDTA were almost the same in increasing the permeability of both Berea and Bandera sandstone cores. GLDA, HEDTA, and EDTA were compatible with Bandera sandstone cores which contains 10 wt% Illite. The weight loss from the core was highest in case of HEDTA and lowest in case of GLDA at pH 11. At low pH values (pH =4) 0.6M GLDA performed better than 0.6M HEDTA in the coreflood experiments. The permeability ratio (final/initial) for Bandera sandstone cores was 2 in the case of GLDA and 1.2 in the case of HEDTA at pH of 4 and 300oF. At high pH HEDTA was the best chelating agent to stimulate different sandstone cores, and at low pH GLDA was the best one. For Berea sandstone cores EDTA at high pH of 11 was the best in increasing the permeability of the core at 300oF.
The low pH GLDA based fluid has been especially designed for high temperature oil well stimulation in carbonate and sandstone rock. Extensive studies have proved that GLDA effectively created wormholes in carbonate cores, is gentle to most types of casing including Cr- based tubular, has a high thermal stability and gives no unwanted interactions with carbonate or sandstone formations. These unique properties ensure that it can be safely used under extreme conditions for which the current technologies do not give optimal results. Furthermore, this stimulation fluid contributes to a sustainable future as it based on readily biodegradable GLDA that is made from natural and renewable raw material.
TABLE OF CONTENTS
TABLE OF CONTENTS xi
LIST OF FIGURES xv
LIST OF TABLES xxiii
INTRODUCTION: THE IMPORTANCE OF RESEARCH 1
Carbonate Matrix Acidizing 1
Optimum Injection Rate for Different Stimulation Fluids 7
Diversion in Stimulation Treatments 9
Effect of Reservoir Fluid Type on the Stimulation of Calcite by HCl 10
Stimulation of Dolomite Reservoirs 11
Stimulation of Sandstone Reservoirs 15
Productivity Improvement Factor 19
Clay Minerals 19
Chelating Agents in Sandstone Stimulation 22
EVALUATION OF A NEW ENVIRONMENTALLY FRIENDLY CHELATING AGENT
FOR HIGH-TEMPERATURE APPLICATIONS 25
Experimental Work 25
Dissolution of Calcite by Chelates 26
Rotating Disk Experiments 27
Thermal Stability Tests 28
Coreflood Tests 28
Results and Discussion 30
Dissolution of Calcite by GLDA: Effect of GLDA pH 30
Effect of Simple Inorganic Salts 33
Effect of Disk Rotational Speed and pH 36
Effect of Temperature on the Calcite Dissolution Rate 37
Thermal Stability Tests 39
Coreflood Experiments 40
Biodegradability of GLDA 49
EFFECTIVE STIMULATION FLUID FOR DEEP CARBONATE RESERVOIRS:
A COREFLOOD STUDY 52
Experimental Studies 53
Coreflood Experiments 53
Results and Discussion 53
Effect of pH Values of GLDA Solutions 53
Stimulation of Long Calcite Cores 67
Effect of GLDA Concentration 69
Effect of Initial Core Permeability 71
Comparing GLDA with HCl and Other Chelates 73
OPTIMUM INJECTION RATE OF A NEW CHELATE THAT CAN BE USED TO I STIMULATE CARBONATE RESERVOIRS 77
Experimental Studies 78
Parallel Coreflood Experiments 78
Damköhler Number Calculations 78
Results and Discussion 80
Optimum Injection Rate for Different pH Values (6-in. Cores) 80
Effect of Core Length 84
Effect of Temperature on the Optimum Injection Rate 87
Calculation of the Damköhler Number 87
Pore Volumes to Breakthrough for Different Stimulation Fluids 91
Factors Affecting the Wormhole 92
Effect of NaCl on the Performance of GLDA During Coreflood 95
Parallel Coreflood 97
V EFFECT OF RESERVOIR FLUID TYPE ON THE STIMULATION OF CALCITE CORES USING CHELATING AGENTS 105
Experimental Studies 106
Experimental Procedures 107
Analytical Model 107
Prediction of the Pressure Drop Across the Core 114
Model Validation 116
Results and Discussion of the Experimental Part 119
Stimulation of Indiana Cores (Water Saturated) by GLDA and
Stimulation of Pink Desert (High Permeability-Water Saturated)
Calcite Cores by Different Chelating Agents 123
Stimulation of Oil-Saturated Indiana Cores by GLDA and HEDTA 125
Effect of Gas 127
Stimulation of Pink Desert (High Permeability-Oil Saturated) Calcite
Cores by Different Chelating Agents 130
VI EFFECT OF LITHOLOGY ON THE FLOW OF CHELATING AGENTS IN
POROUS MEDIA DURING MATRIX ACID TREATMENTS 134
Experimental Studies 135
Dissolution of Dolomite by GLDA 135
Characteristics of Core Samples 135
Results and Discussion 135
Effect of GLDA pH Value on the Dolomite Dissolution 135
Effect of Salts 137
Comparison between Calcite and Dolomite Dissolution by GLDA 138
Effect of Temperature on Dolomite Dissolution by GLDA 139
Optimum Injection Rate in the Coreflood 140
Effect of GLDA pH Value on the Coreflood Experiments 141
Thermal Stability of GLDA 146
Effect of GLDA pH value on the Ca/Mg Molar Ratio 147
VII SANDSTONE ACIDIZING USING A NEW CLASS OF CHELATING AGENTS 149
Experimental Studies 150
Experimental Procedure 150
Results and Discussions 151
Using GLDA to Stimulate Berea Sandstone Cores 151
Effect of GLDA pH Value on the Permeability Ratio of Berea Cores 153
Effect of Injection Rate on the Permeability Ratio of Berea Cores 155
Effect of the Injected Volume of GLDA on the Permeability Ratio 156
Effect of Temperature on the Stimulation of Berea Sandstone Cores 158
Improvement in Skin Damage and Production Rate Using GLDA 160
Permeability Prediction for Berea Cores Treated by GLDA 162
VIII NOVEL ENVIRONMENTALLY FRIENDLY FLUIDS TO REMOVE CARBONATE MINERALS FROM DEEP SANDSTONE FORMATIONS 165
Experimental Studies 166
Experimental Procedures 166
Results and Discussion 167
Stimulating Berea Sandstone Cores with High pH Fluids 167
Stimulating Bandera Sandstone Cores with High pH Fluids 171
Stimulating Berea Sandstone Cores with Low pH Fluids 175
Stimulating Bandera Sandstone Cores with Low pH Fluids 178
REMOVING THE DAMAGE AND STIMULATION OF ILLITIC-SAND STONE I RESERVOIRS USING COMPATIBLE FLUIDS 181
Experimental Studies 182
Results and Discussion 183
Stimulation of Berea Sandstone Using GLDA/HF Solutions 183
Effect of HF Concentration on the Stimulation of Berea Sandstone
Cores Using GLDA/HF 186
Effect of Preflush on the Stimulation of Berea and Bandera
Sandstone Using GLDA/HF 187
Fines Migration by HCl 189
Removing the Damage Caused by Drilling Fluid 191
Stimulation of Scioto Cores and Kentucky Cores 195
X CONCLUSIONS AND RECOMMENDATIONS 197
INTRODUCTION: THE IMPORTANCE OF RESEARCH
Carbonate Matrix Acidizing
Formation damage may be defined as any impairment of well productivity or injectivity due to plugging within the wellbore, in perforation, in formation pores adjacent to the wellbore or fractures communicating with the wellbore. Almost all wells are damaged, the problem is to determine the degree of damage, location, probable causes of damage and approaches to alleviate any serious damage.
Formation damage may be indicated by well tests, pressure build up and draw down tests, comparison with offset well, careful analysis of production history.
If multiple zones are open in a single completion, PLT (Production logging Techniques) runs in a flowing well will often show some permeable zones to be contributing little or nothing to the production. A reservoir study may be required to differentiate between:
ImageProduction decline due to gradual formation damage
ImageDecline due to loss in reservoir pressure, comparison with offset well may not be sufficient to detect gradual damage because all of wells may be subjected to the same damaging mechanisms.
In a relatively high permeability well with skin damage, reservoir pressure may be measured in the well, and it may stabilize within few hours. If reservoir the permeability is low, days or weeks may be required to stabilize the reservoir pressure. Under these conditions, it may be difficult to determine ‗skin‘ damage. Skin damage calculation using pressure build up and draw down analysis are carried out in many areas prior to planning well stimulation.
Once mechanical pseudo skin effects are identified, positive skin effects can be attributed to formation damage. Formation damage is typically categorized by the mechanism of its creation as either natural or induced. Natural damages are those that occur primarily as a result of producing the reservoir fluid. Induced damages are the result of an external operation that was performed on the well such as a drilling, well completion, workover, stimulation treatment or injection operation. In addition, some completion operations, induced damages or design problems may trigger the natural damaging mechanisms.
This dissertation follows the style of SPE Journal.
Natural damages include:
ImageImageFines migration Swelling clays
ImageImageOrganic deposits such as paraffins or asphaltenes Mixed organic/inorganic deposits
Induced Damages Include:
ImageImagePlugging by entrained particles such as solids or polymers in injected fluids Wettability changes caused by the injected fluids.
Carbonate Matrix Acidizing has been carried out for several years using hydrochloric acid-
based stimulation fluids in various concentrations. At high temperatures HCl does not produce acceptable stimulation results because of its fast reaction in the near wellbore area, low acid penetration, and surface dissolution (Huang et al. 2003).
Williams et al. (1979) recommended that carbonate acidizing treatments should be carried out at the highest possible injection rate without fracturing the reservoir rock (qi,max). Wang et al. (1993) discovered an optimum acid injection rate to obtain breakthrough during acid treatments for carbonate cores in linear coreflood using a minimum acid volume. The optimum acid injection rate was found to be a function of the rock composition and reaction temperature as well as the pore size distribution of the reservoir rock. A problem occurs if the required optimum injection rate is greater than the maximum acid injection rate. In this case HCl cannot be used because it will cause face dissolution if used at low injection rates, or will fracture the formation if used at high injection rates. Therefore stimulation fluids other than HCl-based fluids such as chelating agents need to be used to achieve deep and uniform penetration and eliminate face dissolution problems.
Another problem encountered during stimulation using HCl-based fluids is the high corrosion rate of these fluids to the well tubulars. Well tubulars are often made of low-carbon steel and may contain rust. HCl will dissolve the rust and produce a significant amount of iron, which in turn will precipitate and cause formation damage. Corrosion becomes more severe at high temperatures, and special additives are needed to compensate for the loss in corrosion inhibition at higher temperatures. The cost of these additives exceeds 5% of the treatment cost (Fredd 1998). Also the excessive use of corrosion inhibitors may cause other problems, as the corrosion inhibitor may adsorb on the reservoir rock and change its wettability, especially in low permeability reservoirs (Schechter 1992).
Chelating agents have the ability to complex metal ions by surrounding them with one or more ring structures. The process of chelation results in the formation of a metal-chelate complex with high stability. For example, ethylenediaminetetraacetic acid (EDTA) compounds are capable of forming stable chelates with di- and trivalent metals like Fe and Ca (Martell and Calvin 1952).
Fredd and Fogler (1997; 1998a; 1999) investigated the use of EDTA and DTPA to stimulate calcium carbonate cores. They performed linear coreflood experiments using Texas cream chalk and Indiana limestone cores of 1.5 in. diameter and 2.5, 4, or 5 in. length. The porosity range of these cores was between 15 and 20 vol%, and the permeability range was 0.8 to 2 md. They used 0.25M EDTA of pH 4.0, 8.8, and 13.0 with a flow rate of 0.3 cm3/min. The maximum wormhole obtained was at pH 4 with a minimum pore volume required to breakthrough the core (PV = 4.8), whereas at pH 13, a PV of 12.7 was used to breakthrough the core and form a wormhole. Fredd and Fogler (1999) concluded that, the EDTA can effectively wormhole in limestone, even when injected at moderate or non-acidic pH values (4 to 13) and at low flow rates where HCl is not effective. The dissolution mechanism involves chelation of calcium ions and does not require conventional acid attack. The ability to stimulate under acidic conditions combined with the ability to chelate metal ions provides multiple benefits in using EDTA.
Fredd and Fogler (1998b) studied the influence of transport and reaction on wormhole formation during the reaction of chelating agents with calcium carbonate cores. They studied the effect of the Damköhler number (NDa) on the pore volume consumed by the chelating agent to breakthrough the core. The Damköhler number, NDa, can be defined as the ratio of the net rate of dissolution by acid to the rate of convective transport of acid. When the dissolution is mass transfer limited the Damköhler number in this case will be mass transfer limited Damköhler number (NDa(mt)) and can be determined from the following equation:
where; De is the effective diffusion coefficient, Q is the injection rate, and a is a constant and depends on the carbonate core. When the net rate of dissolution is reaction rate limited, the Damköhler number, NDa(rxn), is given by:
where; Ks is the surface reaction rate constant, lp is the pore length, and dp is the pore diameter.
Fredd and Fogler (1998c) showed that DTPA (at pH 4.3) and EDTA (at pH 13 and 4) exhibit an optimum Damköhler number where the number of pore volumes to breakthrough the core was minimized.
Fredd and Fogler (1998c) studied the effect of NaCl and KCl on the rate of dissolution of calcite by EDTA. They observed that the rate of dissolution increased as the ionic strength was increased with adding KCl. In contrast the rate with EDTA was observed to decrease as the NaCl concentration was increased from 0 to 0.7M.
Frenier et al. (2001 and 2003) examined chelating agents with a hydroxyl group to determine their acid solubility and ability to complex iron and calcium under oilfield conditions. Fig. 1 shows the chemical structure of the chelating agents that are used in the oil field industry. Dissolution tests were performed using calcite and gypsum in a slurry reactor for 10-24 hrs. The dissolved calcium ion was determined using ICP. Corrosion tests were run in a high pressure autoclave. The results showed that hydroxyethyliminodiacetic acid (HEIDA) is a very effective complexing agent for Fe3+ in HCl acid solutions. It has a high-capacity to dissolve calcite, gypsum, and fines clean-up. The environmental impact of HEIDA is less than that of EDTA, as HEIDA is more biodegradable than EDTA (for HEIDA more than 90% was degraded within two weeks, however in the case of EDTA, less than 5 % was degraded within 28 days) (Frenier et al. 2003).
Huang et al. (2003) tested 10 wt% solutions of acetic acid, Na4EDTA and long-chained carboxylic acid (LCA) using Indiana limestone cores of 1 in. diameter and 4 in. length. These cores have porosities of nearly 15 vol% and permeabilities of 2 to 3 md. The dissolving power of 10 wt% LCA was measured to be 0.45 lb/gal at room temperature. They performed core flow tests at 250oF at different flow rates to determine the optimum injection rate to breakthrough the core will minimum pore volume. All the three chemicals used formed wormholes in the tested cores..