Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Formation damage occurs during the lifetime of many wells. Loss of well performance due to formation damage has been the subject of several review articles. Fines migration, water, emulsion blockage, inorganic scale, asphaltene, and other organic deposition are a few mechanisms that can cause formation damage. The present paper discusses new formation damage mechanis ms that are caused by various chemical treatments. These include: adsorption-type scale squeeze treatments (phosphonate-based inhibitor), solvent treatments (a neat mutual solvent) to remove water blockage in a tight carbonate reservoir, and regular mud acid (HCl:HF at 12:3 weight ratio) to remove drilling mud filter cake in sandstone reservoirs. These treatments were designed to remove a known form of formation damage. However, they created new forms of formation damage, which resulted in a significant decline in the performances of several wells. Case studies of new damaging mechanisms that resulted from various chemical treatments are discussed in this paper. Details of lab and fieldwork that were performed to identify the damaging mechanisms and determine its impact on well performance were addressed. Finally, the paper highlights the remedial actions and field application that resulted in restoring the performance of various wells without affecting the integrity of the formation. Introduction Formation damage can occur during the lifetime of all wells starting from drilling, completion, production, and stimulation. Basically, it causes loss of well performance, and usually requires an expensive treatment to remove such damage. Formation damage can be divided into two main categories: mechanical and chemical damage. Mechanical damage occurs when particulate solids, emulsion, asphaltene, or inorganic scales physically plug the pore spaces. A typical example of formation damage due to suspended solids occurs in water injectors. Oil droplets can also cause damage to disposal wells, especially in the presence of suspended solids. In both types of wells, suspended solids and oil can plug the formation and cause loss of well injectivity. Another important example of mechanical formation damage is injecting or producing oil or gas wells at high rates. In this case, the fluids will exert high drag forces on clays and feldspars, which can dislodge fine particles. The mobilized fine particles accumulate at the pore throats, and cause formation damage. This type of damage occurs in sandstone reservoirs, which contain kaolinite and other migratory clay particles. Formation damage due to chemical means occurs in many reservoirs. Injection of low salinity water into a sandstone reservoir with high salinity water is a typical example. In this case, the lower salinity water will trigger clay swelling and fines migration. Both can cause severe formation damage, especially in tight formations. Another example is the injection of incompatible water. If the injection water contains high sulfate content (seawater is a typical example) and the formation water contains high concentrations of calcium, strontium, or barium ions then the sulfate salts of these cations will precipitate in the formation and may cause severe formation damage. An example of mixing incompatible waters occurs when disposal waters which typically contain high hydrogen sulfide content are mixed with injection water, which contains dissolved iron. Iron sulfide species will precipitate upon mixing of these two waters, and can cause severe loss of injectivity.
- Europe (0.94)
- North America > United States > Louisiana (0.29)
- Asia > Middle East > Saudi Arabia (0.29)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.56)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.55)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract Although hydrochloric acid has been used for more than 60 years to matrix acidize carbonate reservoirs, the process is still as much art as science. Historically, design engineers have used a "rule-of-thumb" based on field experience to quantify the design parameters for a candidate well. However, each well is different and this "generic" approach for treatment design can result in under- or over-treating. This paper is directed at matrix acidizing of vertical water injection wells completed in a heterogeneous carbonate reservoir (Arab-D) in Saudi Arabia with focus on field validation of a commercial matrix acidizing design simulator. The "validation" process allows the production engineer to "calibrate" the simulator for his specific field, and use it with confidence to improve treatment designs. In this field study three matrix-acidized injection wells were used for validation of the carbonate acidizing model. The wells were completed in 150 to 200 feet openhole intervals in a reservoir composed of a variety of limestone - dolomite mixtures. Treatments were performed using hydrochloric acid along with particulate diverter stages, which was bullheaded down casing. The post-treatment model validation process consisted of simulation of the actual treatment using various values of "acidizing efficiency" to yield an acceptable match with the final skin. Subsequently, a comparison of the simulated and actual surface treating pressure, and the pre-post-treatment wellhead pressure during seawater injection was made. A detailed description of the validation process and the supporting well data are presented. A good match of predicted surface pressure and actual wellhead pressure obtained from the treating report adds credibility to the simulator. Normally, the difference in actual and simulated pressure was less than 10%. Pressure data indicate that the benzoic acid/rock salt diverter systems were inefficient. The simulator indicates diverter inefficiency causes the high permeability zones to become "thief zones" resulting in non-uniform acid distribution. In all cases the pressure dropped 25 to 50% within ten minutes following injection of acid into the formation. An internal acidizing efficiency factor was increased to allow the predicted skin of the simulator to approximate the actual skin determined from a falloff test. It was discovered that the optimum efficiency factor was a function of the amount of dolomite in the reservoir. Guidelines for the determination of the efficiency factor based upon mineralogy are presented along with an explanation for this and other observations. Introduction Matrix acidizing of a carbonate reservoir is designed to bypass the damage via creation of wormholes to yield a high permeability region radially around the wellbore. During the process a negative skin is created to yield higher injection or production than obtained from an undamaged well at the same conditions. This is true reservoir stimulation. Although the design process should be based upon a sound engineering methodology, normally it is not. The methodology should consist of several steps including candidate selection, damage characterization, treating fluid/additive selection, treating fluid volume determination, calculation of the maximum injection rate/surface pressure, and placement strategy. Design engineers have historically used a "rule-of-thumb" based on field experience to develop the treating fluid system, to quantify the acid volume, and develop the treatment schedule although each well is unique. This approach can result in under- or over-treating as discovered during this study. This paper is directed at the field evaluation of a matrix acidizing simulator based upon matrix acidizing treatments performed in water injection wells (PWI, SWI and PWI/SWI) completed in the Arab-D formation. A field-validated simulator can be used with confidence during the treatment design process to develop the optimum treatment, and improve treatment success/economics. Carbonate acidizing physics/models are not discussed in detail in this paper, yet they are available in the literature.
- Asia > Middle East > Saudi Arabia (1.00)
- North America > United States > Texas (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
Abstract Application of citric acid for damage removal in both clastic and carbonate rocks has historically not received widespread acceptance due to formation damage concerns regarding precipitation of calcium citrate. In addition, usage of citric acid in place of hydrochloric acid has been avoided due to lower bulk carbonate dissolving power relative to hydrochloric acid. However, environmental, safety, and corrosion concerns with using hydrochloric acid have sparked renewed interest in citric acid for stimulation. This paper reconsiders the use of citric acid as both an additive to conventional hydrochloric acid systems and as a stand-alone acidizing fluid. The paper reviews extensive laboratory work focused on understanding reaction pathways and geochemical precipitation issues, and takes a new look at paradigms related to the calcium citrate issue. Laboratory studies performed independently by two research laboratories address two main areas of investigation:Evaluation of potential geochemical reaction paths and precipitation of calcium citrate and mechanisms for generation of differential etching in two carbonate rock lithotypes. The described mechanism for etching enhances conductivity in a contrasting mode compared to hydrochloric acid. Findings based on this work provide new insights into the applications, usage and potential limitations of citric acid. A newly proposed process for downhole reaction is presented. This process differs greatly from long-held paradigms built on a foundation of bench-top experimentation. Factors controlling downhole reactions are disclosed and the results of core testing and fracture conductivity are presented. Introduction Organic acids have been used to stimulate carbonate reservoirs. The two main organic acids that are frequently used in the field are formic acid (HCOOH) and acetic acid (CH3COOH). These acids are less reactive with carbonate rocks than hydrochloric acid. Acetic acid is weakly ionized in aqueous solutions with a Ka of 1.8×10. Acetic and formic acids are less corrosive than mineral acids and can be inhibited. For example, acetic acid can be inhibited against all types of steel at elevated temperatures for extended periods of time. Therefore; organic acids are used to stimulate high temperature wells where corrosion rates due to HCl are too high. Mixtures of organic acids have been used to stimulate high temperature/pressure wells in the Arun limestone field in Indonesia and to remove calcium carbonate scale in gas wells in the Merluza field. However, organic acids are more expensive than HCl per unit volume of rock dissolved. They cannot be used at high acid concentrations. Typically, acetic and formic acids are used at concentrations less than 10 wt%. This is because the reaction products (especially calcium formate) can precipitate at high acid concentrations. In addition, the reaction of organic acids with calcite is complex because the reaction is reversible and thermodynamically limited by the presence of reaction products. In other words, the reaction is controlled by the diffusion of the reaction products away from the rock surface. Calcium chelating agents (non-acid formulae) were introduced as stimulating fluids by Fredd and Fogler. They used ethylenediaminetetraacetic acid (EDTA) solutions as new stimulation fluids for carbonate reservoirs. EDTA solutions are thermally stable, not corrosive and do not form sludges when contacted with acid-sensitive crude oils. A unique feature of non-acid formulae is that wormholes can be created at high pH values. Effective stimulation of carbonates can be achieved with EDTA solutions at much lower flow rates than those required for regular HCl acid. Citric acid has historically been used in oilfield treatments as an iron-control chemical. Because of its structure (Fig. 1), it has been used to stabilize iron in spent HCl acids and prevent iron hydroxide and iron sulfide precipitates. Citric acid has three carboxylic (COOH), and one hydroxyl (OH) groups. These groups play a key role in citric acid reactions. Citric acid is capable of forming two different types of complex compounds. It forms water-soluble and water-insoluble complex compounds. When complexing Mg, Ca, and Fe (III), citric acid behavior as a sequestering agent forming water-soluble compounds, or as a chelating agent forming water-insoluble compounds, depends mainly on the following parameters: ionic strength, pH, and temperature.
- North America > United States > Texas (0.28)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.24)
- North America > Canada > Alberta > Clearwater County (0.24)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.
- Asia > Middle East > Saudi Arabia (0.95)
- North America > United States (0.68)
- Europe > Netherlands > South Holland > The Hague (0.24)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.47)