Acid-etched Fracture Research Articles

Continuous Improvements in Acid Fracturing at Lake Maracaibo

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96531, "Acid Fracturing in Lake Maracaibo: How Continuous Improvements Kept on Raising the Expectation Bar," by B. Burgos, Shell Venezuela S.A.; M. Buijse, SPE, Shell Intl. E&P; E. Fonseca, Shell Venezuela S.A.; and A. Milne, M. Brady, SPE, and R. Olvera, Schlumberger, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October. The Maraca limestone formation is a part of the Cogollo carbonate group below Lake Maracaibo, Venezuela. Acid fracturing with an organic-acid system has proved to be a pivotal completion strategy for achieving higher productivities and increasing reserves. The main challenges are the relatively high hydrogen sulfide (H2S) content, 280°F reservoir temperature, the asphaltenic nature of the crude, and the long completion tubing that limits pump rate. Introduction The Maraca limestone formation is a 20- to 30-ft upper member of the Cogollo carbonate group at 15,000 to 16,000 ft in the Urdaneta West field below Lake Maracaibo, Venezuela. Reservoir volumes and productivity are attributed mainly to matrix development, in contrast with the rest of the Cogollo, where natural fractures play a major role in well production. When stimulation and development strategy began focusing on the Maraca group, a number of matrix stimulations were performed, most using coiled tubing (CT) at low pumping rates and volumes. The first few treatments used 15% hyrodochloric acid (HCl), but the acid system was switched quickly to an organic acid blend (13% acetic and 9% formic) because of the high reactivity of the HCl and its tendency to form sludge after contacting the asphaltenic Maraca oil. These matrix treatments had modest results, and the gained productivity was lost after a few months of production. Acid Fracturing With Organic Acid Acid fracturing was considered as an alternative to stimulate Maraca wells. Not only would acid fracturing increase well productivity, but it also would help retain the generated conductivity for a longer time period. Acid fracturing is a stimulation technique where acid, usually HCl, is injected into the reservoir at fracturing pressures. As the acid flows along the fracture, the fracture face is dissolved in a nonuniform manner, creating conductive or etched channels that remain open when the fracture closes. The effective fracture length is a function of the type of acid used, the acid reaction rate, and the fluid loss from the fracture into the formation. Acid fracturing was preferred to hydraulic fracturing because proppant cleanout in a sour well with CT required operational and safety resources not yet in place. Additionally, the high conductivity of an acid-etched fracture made acid fracturing a more attractive technique if comparable fracture lengths could be achieved.

Acid Fracturing Technique for Carbonate Reservoirs Using Nitric Acid Powder

Abstract The length of the etched fracture is rather limited utilizing traditional acid fracturing techniques, especially in a high-temperature carbonate reservoir. Although the propped fractures may have a deeper penetration, they have such drawbacks as low fracture conductivity, unintended proppant bridging, and subsequent proppant flow back. This paper presents the development of a new acid fracturing technique, Nitric Acid Powder (NAP) acid fracturing, to improve the acid penetration and fracture conductivity. The NAP acid fracturing technique has been applied in several oil fields in China. It has been shown that the NAP acid fracturing technique has the advantages of both hydraulic fracturing and acid fracturing, such as long effective penetration, high fracture conductivity, low cost, and easy field operation. We have developed a comprehensive mathematical model for the NAP acid fracturing technique to facilitate the optimization of the field treatment design. The model presented considers fracture growth, acid transport and reaction, leak-off, etched width of the fracture, and so on. The study has shown that the NAP acid fracturing technique could reach a very high stimulation ratio, even in a high-temperature carbonate reservoir. Therefore, it is an innovative and promising technique for well stimulation in carbonate reservoirs. Introduction Carbonate formations generally have a low permeability and can be highly fissured. Long fractures in acid fracturing treatments are essential to maximize production. Acid must react with the walls of the fracture to form a channel that remains open after the treatment. Flow channels can be formed as a result of an uneven reaction with the rock surface or preferential reaction with minerals heterogeneously distributed in the formation. If the formation temperature is very high, the reaction rate will be fast. If this occurs, the acid treatment will tend to remain in the near wellbore vicinity, resulting in short penetration. Acid fracturing techniques are the primary preference in carbonate formations. Operationally, acid fracturing is less complicated because no propping agents are used, which eliminates the risk of a screen-out and subsequent problems of proppant flowback and cleanout from the wellbore. Generally, acid-etched fractures have high conductivity, although they are quite limited in penetration, whereas the propped fractures have limited conductivity with deeper fracture penetration. The techniques to overcome the limitations of conductivity and penetration for the carbonate formation have been studied continuously to enhance the acid fracturing technology. Equilibrium acid fracturing was developed by Tinker(1) to maximize the contact time of acid with the fracture face to get a high fracture conductivity in cool dolomite formations, which react slowly with acid. Maximum acid contact time is essential to create highly conductive etched channels on the fracture faces. After the designed fracture length is created, the injection is continued at certain rates to maintain the equilibrium with the fluid leak-off rate from the created fracture faces. This technique was proven to be effective in stimulating the relatively cool dolomite. Closed acid fracturing techniques(2) were designed to obtain high conductivity, especially for the formations with extra high fracture close stress.

Acid-Fracturing Treatment: A Surface-Topography Analysis of Acid-Etched Fractures To Determine Residual Conductivity

Summary A fracture-acidizing treatment of carbonate formations can be considered successful when a relatively good fracture conductivity remains after treatment. To reach such a goal, an uneven etching of the fracture by acid is expected, so that channels are created that hydraulically maintain the fracture open, once the pressure is released after the job, and thus enhance productivity. Residual conductivity is the consequence of uneven etching of the surface, but the way this etching occurs in the field is not well understood and, therefore, poorly described. We, thus, propose, in this paper, an experimental methodology to investigate and characterize quantitatively how acid injection conditions affect the fracture surfaces, how the created rough surface is able to support the stress, and, finally, how fracture conductivity can be estimated from the surface topography. The statistical investigation of surface topography associated with acidizing experiments proposed in this paper, provides a new and interesting method for designing an acid fracturing job. It can be used as an aid to select the best fluid formulation and flow rate for a given formation type and well conditions and to forecast the behavior of the fracture after the treatment.

Acidizing Concepts - Matrix vs. Fracture Acidizing

Acidizing involves a wide range of stimulation treatments that can yield impressive production increases in many wells if properly applied. Acidizing treatments are divided into two categories: matrix acidizing and fracture acidizing. To use either treatment properly, an understanding is required of what the treatments do and what is necessary to stimulate the well.

Fracturing in Chalk Completions (includes associated papers 14483 and 14682 )

Summary Chalk reservoirs are an exploration objective in parts of the North Sea and elsewhere but, because of their low permeability, usually require stimulation to produce economically. However, conventional stimulation methods frequently fail to give the expected improvement in productivity. Research has shown that this is caused by certain specific properties of chalk: low hardness, homogeneity, lack of fracture barriers, and pore collapse under stress. Acceptable increases in productivity have been obtained when these properties were accounted for properly in the design. Introduction Hydrocarbons have been found in chalks in the North Sea, the Middle East, the U.S. gulf coast and midcontinent regions of the U.S., and the Scotian Shelf of Canada. Chalk is typically very porous but impermeable and soft; it is also rather homogeneous and massive. Because the permeability is so low, effective fracture stimulation is normally a prerequisite for the development of chalk reservoirs; even where secondary permeability is present, fracturing may give an attractive increase in productivity. During the 1970's, production from chalk, particularly in the North Sea and Middle East, became of interest to the Shell Group. Our initial experience with conventional acid and hydraulic fracturing techniques, however, was not very successful; the postfracture productivity frequently was poorer than expected and declined rapidly. Similar experiences have been reported by others. The failure to obtain sustained productivity improvement initially was attributed to the softness and homogeneity of the chalks we were dealing with. It was reasoned that softness would lead to the embedment of proppant and the loss of fracture conductivity in hydraulic fracturing, while the homogeneity of the chalk would give evenly etched walls in an acid fracture treatment, resulting in very low fracture conductivity when the fracture pressure is released and the fracture closes. Moreover, any ridges left after the acid fracturing process may be too soft to withstand the stresses imposed by production. Therefore, research to improve the available stimulation techniques focused on overcoming these specific problems; we found, however, that two other properties also play a role and must be considered in the design. These arethe ductile behavior of chalk, which can cause pore collapse and loss of permeability, andthe lack of significant fracture barriers, which leads to radial fracture development. Etched-Fracture Conductivity We use the apparatus described in the Appendix to measure acid-etched fracture conductivity in the laboratory. A typical result is shown in Fig. 1, where the dashed line shows the fracture conductivity of a chalk sample etched with an acid emulsion, plotted as a function of closing stress. It can be seen that the initial fracture conductivity is low and disappears under increasing stress. Such a result is typical of chalks, no matter what kind of acid is used (plain, gelled, or emulsified). This is caused by the homogeneity of the chalk, which results in evenly etched fracture walls, and by its softness, which causes any ridges left after the acidization to collapse under the stresses imposed by production. To obviate the problems of homogeneous etching, we make use of the phenomenon of viscous fingering. A high-viscosity, nonreactive preflush is used to create the fracture through spaced perforations, and is followed by the injection of low-viscosity acid, which fingers through the viscous preflush as indicated in Fig. 2. This etches the fracture walls irregularly; the technique, WISPER, derives its name from these widely spaced etched ridges. An example of the acid-etched fracture conductivity induced in a sample by means of the WISPER technique also is included in Fig. 1. Comparing the results it is clear that the viscous-fingering technique induces a higher etched fracture conductivity. Unfortunately, in this particular example, the acid-etched fingers collapse and the conductivity is lost under stress. This problem is common in chalks and, as illustrated by Fig. 3, is dependent on the formation hardness [throughout this paper we use the Brinell hardness number (BHN) as a definition of hardness]. To produce these data, we milled a groove in the sample as shown in the top left corner of the figure and measured the conductivity of this groove as a function of time and stress. Fig. 3 shows the fracture conductivity measured after 1,000 hours at a given stress. We chose to mill the groove, rather than acid-etch the sample, so that all the three samples used, taken from the same North Sea well, would have the same initial fracture conductivity. The results demonstrate that increasing stress will result in a strong decline in fracture conductivity, which indicates that the conductivity of acid-etched fractures is sensitive to reservoir depletion. In the field from which these samples were taken, the effective stress acting on the fracture face after closure is estimated to be about 130 bar [13 MPa]. JPT P. 73^

Matrix Acidizing

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Introduction Many excellent and useful papers have been written on the subject of matrixacidizing. Included in this article is an extensive bibliography that should beuseful to the engineer in the design and execution of a matrix acidizing treatment in limestone or sandstone formations. The first matrix acidizing jobswere very successful in stimulating oil production in carbonates. However, mostof the recent attention to matrix acidizing concerns sandstones and the use ofvarious hydrofluoric acid systems. Matrix acidizing in carbonate formations still is beneficial in high-permeability, damaged formations (50 md or more). Damage can occur during drilling, completion or production of a well. Incarbonates with permeabilities less than 10 md, acid fracturing generally is used because much greater stimulation is obtained with long, acid-etched fractures in low-permeability reservoirs. Although the acid systems used insandstones and carbonates differ, the same practices apply to both. Well Performance (Need for Acidizing) Successful acidizing depends on the presence of damage and its location and intensity. The closer the damage is to the perforations, the more easily acidcan get to it. Compacted or crushed zone damage from perforating overbalancedcan be removed easily by acid, since only about 1/2 in. [1.3 cm] of damage mustbe removed directly around the perforation. Precipitates from previous acid treatments more than 1 ft [0.3 m] from the wellbore in sandstone or 5 ft [1.52m] in carbonate will be either impossible to reach with matrix acidizing or too expensive to treat. Deep solid plugging, will be corrected more effectively bycreating a conductive fracture through the damage either by sand fracturing oracid fracturing. Nonplugging damage (e.g., oil wetting) may be several feet deep around the wellbore, but reverse wetting surfactants can penetrate andreverse the formation to a water-wet condition at reasonable cost. Oil wetting damage usually is less severe than solid plugging damage, so correctivechemicals can reach the affected area easily. High-permeability formations (those with 100 md or more) seem to be dominated by either formation damage or tubing size flow restrictions. This is particularly true of gravel-packed offshore wells. When well flow is markedlyless than similar wells in the same reservoir, most of the drawdown probably isoccurring at the wellbore through a small zone of reduced permeability. Mostrecent gravel-pack-damage research has focused on gravel-packed tunnels andquality of the gravel in the tunnel. Current techniques have improved so muchin recent years that gravel-packed tunnels usually offer little flow resistance when perforating density is adequate. Nevertheless. reduced flow throughgravel-packed wells still occurs. Current research focuses onincompletely packed tunnels andformation-sand damage near the entrance to the tunnels. Torrest and Stein described gravel shifting in tunnels when the gravel pack is not packed tightly during placement. Damage to formation sand before gravelplacement will cause premature pressure outs resulting from viscous fluidsentering damaged or reduced permeability near the perforations. Because of highpressures, pumping may be halted before the gravel has concentrated adequately in the perforation tunnels. If the pumping stops too soon, the tunnels will befilled only partially with quality gravel. When the well is produced, formations and will enter the tunnels, bridging on the gravel inside the tunnel andpacking the partially void tunnel with formation sand, which is much lower inpermeability than the gravel. As the formation sand fills the tunnels. the pressure drop through the completion increases and the flow rate declines. JPT P. 2055^