Water-sensitive Formations Research Articles

A Look at Cement Bond Logs

Despite its potential, the cement bond log is probably one of the most abused, misused, and misunderstood logs used in the oil field today. Miscalibration, inadequate information, and a severe lack of standardization are enough to push petroleum engineers into a morass of bewilderment. Introduction Well cementing technology in both relatively straight and high-angle directional holes has advanced dramatically since the first casing was cemented in 1903. Besides the everyday cementing needs in "problem-free" boreholes, recent engineered improvements successfully deal with cementing of arctic wells, ultradeep and hot holes, water-sensitive formations, and proper placement opposite incompetent, fractured, or proper placement opposite incompetent, fractured, or highly permeable formations. The basic requirements for obtaining a successful primary cement job have been known for years. Good primary cement job have been known for years. Good design characteristics are based on a knowledge of formation, cement, and pipe properties, and controlled placement techniques that consider fracture gradients. Also important is an understanding ofminimum practical mud density and viscosity,cement type,turbulent flow conditions,the optimum size of preflushes,centralizing of casing, the use of scratchers, and the handling of pipe, andthe proper choice of casing. For more than a decade now, the oil industry has used wireline well logging, such as cement bond logging, to detect the presence of cement behind pipe and to evaluate the bond of the cement to both the casing and the formation. The validity of Cement Bond Log (CBL) interpretation has been a subject of controversy since its introduction; and the CBL, despite its great potential, is probably one of the most abused, misused, and misunderstood logs run in the oil field today. To make matters worse, tools run by service companies use various gating systems, spacings, frequencies, etc. This lack of standardization, in addition to poor sonde centering, miscalibration of tools, and inadequate information on log headings, has more than once confused unsuspecting petroleum engineers. In the present discussion, CBL's are reviewed as to the information obtainable and as to how they are interpreted. Comparative field tests and specific observations illustrate some of the pitfalls and possible misinterpretations if logging operations are not designed properly or run correctly. The CBL, if properly run and interpreted, is an efficient aid in estimating cement bond quality. Usually the log consists of an amplitude curve measuring a specific part of the acoustic signal; and since interpretation of the amplitude curve alone may be inconclusive and misleading, supplemental data are normally included. The latter may be one or more of the following:transit time to the first event of the acoustic signal reaching a minimum or predetermined amplitude,amplitude of the formation predetermined amplitude,amplitude of the formation signal,variable intensity, andoscilloscope pictures. Additional measurements, although not pictures. Additional measurements, although not directly related to cement bonding, can also be included on the CBL. These usually include the gamma ray curve and casing collar log. JPT P. 607

Field Results From Wells Treated With Hydroxy-Aluminum

More than 200 wells have been treated with hydroxy-aluminum to stabilize reservoir fines. There have been many outstanding successes and few well defined failures. For wells whose production declines rapidly after acid stimulation, for wells that sand up, and for steam-stimulated wells in water-sensitive formations, hydroxy-aluminum could be the best solution. Introduction New, effective well treatments to prolong the economic production of wells in the U.S. are vital to the domestic gas and oil industry. Field results show that the hydroxy-aluminum process is such a treatment. Nearly all gas and oil formations contain clay minerals of different types and in various amounts. Serious permeability decreases occur when clay minerals obstruct flow by either dispersing and lodging in restrictions or expanding to fill pore spaces. In many sandstone formations, clay minerals are the principal cementing agents for sand and silt grains. A clay-mineral fabric can be weakened by changes in water saturation or composition, by treatment with acids, and by many other materials now used in well treatment and maintenance. The formation then becomes less competent and may start to erode or flow. Reed reported that hydroxy-aluminum (OH-Al) stabilizes formation clay minerals against dispersion and expansion. This prevents permeability caused by migrating and expanding clays. Reed and Coppel found that in certain formations if the clays are treated with OH-AL to make them more resistant to changes in water composition, the sand and silt fractions becomes less subject to erosion. Refs. 2 and 3 dealt primarily with laboratory work; they described the effectiveness of the process for clay stabilization, defined the critical process variables, and discussed sand stabilization. The purpose of this paper is to present the results of extensive field testing of the hydroxy-aluminum process in several types of applications. The Hydroxy-Aluminum Process Description of the Solution Hydroxy-aluminum is a low-cost, inorganic polymer that is available commercially. It can also be successfully prepared in the field in large quantity by reacting aluminum chloride and sodium hydroxide in a high-shear mixing device. It is a slightly acidic, nonhazardous chemical and no unusual handling procedures are required. Details of its chemistry and interactions with clay minerals are given in Ref. 2. Job Design In designing a job, two things must be considered, the process steps and the liquid volumes. process steps and the liquid volumes. The process, for most field applications, consists of the following three steps: injecting the hydroxy-aluminum, overflushing to displace the hydroxy-aluminum, and curing. The hydroxy-aluminum is injected for the purpose of bringing it into contact with the clay mineral surfaces. In the field tests to date, it appears that this can be accomplished in the formation without the need for special solvents or wetting agents. The purpose of the overflush is to assist in placing the hydroxy-aluminum and to remove excess placing the hydroxy-aluminum and to remove excess hydroxy-aluminum from the pores. JPT P. 1108

Stabilization of Formation Clays with Hydroxy-Aluminum Solutions

To protect water-sensitive formations against permeability damage by fresh water, a material is needed that will adhere very tenaciously to both external and interlayer surfaces of clay minerals. This paper describes the use of hydroxy-aluminum solutions to stabilize formation clays against dispersion and structural expansion. Introduction Nearly all formations of interest to the petroleum industry contain clay minerals. Serious permeability decreases can occur when clay minerals obstruct flow by either expanding to fill pore spaces or dispersing and lodging in restrictions. Structural expansion occurs when additional water is adsorbed between clay layers. Montmorillonite under reservoir salinity conditions has two or three layers of water between interlayer surfaces. This gives a basal spacing of 15o to 18A. If the formation brine is diluted with fresher water, additional water is absorbed between theo layers until the basal spacing is perhaps 30A or more. If large amounts of expanding clays (often called swelling clays) are present, a very significant fraction of the flow channels may be consumed by the increased clay volume. Generally, however, expanding clay minerals are present in relatively small amounts, and problems from structural expansion are not so widespread as was once thought. Particle dispersion and migration is a much more important damage mechanism, because it can cause serious damage with only very small amounts of clay present. Clay particles dispersed in flow channels present. Clay particles dispersed in flow channels are carried downstream until they lodge in constrictions. Miniature filter cakes are formed by these obstructions, plugging the pores, and reducing permeability according to the fraction of pores plugged. permeability according to the fraction of pores plugged. A specific force acting on expanding clays to expand their structure is caused by the affinity that exchangeable interlayer cations and interlayer surfaces have for water. A logical means of decreasing this tendency to expand in fresh water is to replace the exchangeable cations with cations less inclined to attract water to interlayer sites. Amines have been used but they have the disadvantages of (1) being expensive, (2) tending to oil wet the formation surfaces, and (3) eventually being displaced from surfaces by reservoir brines. Another force that causes both structural expansion and particle dispersion results from the inherent negative charge on almost all clay minerals. This charge is neutralized by adsorption of cations on clay surfaces. Since the cations tend to dissociate, a positive ion swarm is established in the solution near positive ion swarm is established in the solution near the surface of the particle and, of course, a negative charge exists within the particle. This is normally referred to as an electric double layer. Particles with such double layers repel each other; hence, they tend to disperse. Since the strength of repulsion is directly related to the dissociative tendency of the adsorbed cations, more firmly attached cations tend to decrease the double-layer thickness thus the tendency of the particles to disperse. Multivalent cations such as particles to disperse. Multivalent cations such as calcium, magnesium, and aluminum are much more tightly adsorbed than monovalent cations such as sodium, potassium, and lithium. Multivalent cations prevent clay damage while they remain in place and prevent clay damage while they remain in place and Ca has been used successfully to treat water-sensitive formations. JPT P. 860

Low Fluid Residual Fracturing

ABSTRACT A new process of fracturing virtually eliminates the requirement for loadfluid recovery. Liquid carbon dioxide makes up 80 per cent of the total fluidvolume injected, and this fluid gasifies after a short, period of time in thereservoir. Propping agents are carried at a high concentration in a smallside-stream of gelled alcohol, and then blended with the liquid CO2 pumped into the well. After the C02 gasifies in the formation, onlythe alcohol remains for recovery as a fluid or vapor. The process is primarilydesigned for fracture stimulation of low-permeability gas wells. INTRODUCTION FRACTURING OF LOW-PERMEABILITY Reservoirs has always presented the problemof fluid compatibility with the formation core and formation fluids, particularly in gas wells. For example, many formations contain clays whichswell when contacted by aqueous fluids causing restricted permeability, and itis not uncommon to see reduced flow through gas-well cores tested with variousoils. In the past, the approach to the swelling problem has been the use ofchemical additives, such as salts or pH control additives, to water forfracturing water-sensitive formations. Where hydrocarbons are used, lightproducts such as gelled condensate have seen a wide degree of success, but arerestricted in use due to the inherent hazards of pumping volatile fluids. Amore recent technological improvement to the fracturing ofpermeability-sensitive reservoirs essentially eliminates contact of theformation with any fracturing fluids at all. Stimulation is effected byfracturing the well with liquid carbon dioxide as the basic fracturing fluid.Propping agents are blended in a separate stream of gelled alcohol and blendedwith the C02 in the well. The net effect is that the well isfractured with a base fluid with liquid properties. After a short period oftime in the formation, however, the CO2 gasifies, leaving only a lowfluid residual (LFR) of alcohol to recover. This alcohol, in turn, is solublein reservoir gas (methane) and is essentially returned as a vapor. TREATMENT MECHANICS Earlier experimentation with LFR fracturing indicated that the alcohol hadto be gelled to a viscosity of 20 centipoise or higher in order to besufficient to carry the high concentration of proppant agent through theblender and pumping equipment. Alcohol was chosen as the proppant-carryingagent in view of its compatibility with most gas reservoirs, its low freezingpoint and its potential chemical benefit to the stimulation. Alcohol is alsocompletely compatible and miscible with CO2 for immediate blendingof the two fluids.

Effect of Pressure Drawdown on Clean-Up of Clay- or Silt-Blocked Sandstone

Abstract Previous studies have shown that the permeabilities of sandstone cores are markedly reduced following exposure to drilling fluid and subsequent clean-up with oil at high-pressure gradients. Laboratory experiments reported in this paper indicate that permeability damage from drilling mud or water can be substantially avoided through use of an initial low-pressure gradient followed by gradually increasing gradients during clean-up by reverse oil flow. On the other hand, attempts to improve the permeability of damaged Berea and oil formation cores with high-rate oil back flush (simulated well stimulation) and low-rate clean-up gave erratic results. Essentially complete permeability repair was achieved in most of the fresh water-damaged cores from Miocene and Pliocene oil-producing formations; only minor improvement was noted generally in tests with both water- and mud-damaged Berea sandstone. Field well stimulation treatments using high-rate backflush resulted in long-term productivity improvement when production was brought in at gradually increasing production rates and then restricted to a steady value less than the maximum possible rate. Wellbore plugging at high production rates correlated with increasing solids content in the produced oil. Observations and results from these tests agree with current concepts that formation damage in water-sensitive rocks results from movement and bridging of formation fines, rather than from clay swelling alone. Introduction Many laboratory studies's have shown that the permeabilities of sandstone cores are often markedly reduced following exposure to fresh water or water-base drilling mud filtrate. However, work with cores in the restored state has demonstrated that, although permeabilities to water may be very low for sandstones containing hydratable clays, flow of oil can often restore a substantial portion of the effective permeabilities to oil. Nevertheless, water invasion into water-sensitive sandstone cores results in varying degrees of permanent reduction in permeability to oil. Based on field data, Wade's statistical studs of well completion effectiveness also indicated a correlation between productivity damage and water invasion during completion. Similar damage can result from fluid invasion during workover. Nowak and Krueger and Bertness observed in their early work (1951-53) that formation damage in water-sensitive sandstones was associated not only with swelling of expandable clays but also with movement of dispersed particles. Subsequent work by Monaghan et al. (1959), Atwood (1964), Mungan (1965) and Gray and Rex (1965) has led to general acceptance of the hypothesis that permeability damage in water-sensitive formations is caused by migration of finely dispersed minerals and bridging in "brush heap" arrangements at pore constructions. In laboratory studies, Monaghan et al. found the use of chemicals to be of only minor value for repairing formation damage. Atwood, however, was successful in substantially repairing damage in a number of low-permeability cores using an n-hexanol flush. In the field, except for treatments with acids, the use of chemical washes to reduce wellbore damage has had limited and sporadic success and generally is unpredictable. A statistical analysis of stimulation treatments in silt-blocked wells has shown that physical manipulation of wash materials is more important than chemical composition. The recent work reported on formation damage in water-sensitive sands brings to mind the results of some unpublished exploratory work done in 1954 in connection with drilling fluid studies. This laboratory work and subsequent field stimulation treatments indicated a beneficial effect of controlled pressure drawdown and the associated production rate on formation clean-up. This paper reports the results of this work and more recent supplemental experiments on the clean-up of water-sensitive sandstones damaged by water or filtrate invasion. PERMEABILITY RECOVERY AFAR DAMAGE BY DRILLING MUD APPARATUS AND TEST SAMPLES A drilling mud circulating system was used to expose cores to simulated wellbore conditions. JPT P. 397ˆ

Effect of Steam on Permeabilities of Water-Sensitive Formations

Abstract Steam permeability measurements have been made in the laboratory on several samples of natural reservoir materials. The steam temperatures and pressures were selected to simulate conditions which might exist in a reservoir during the injection of steam. For each sample tested, the experimental permeability to superheated steam was comparable to that measured with air and no evidence of plugging was detected. Some samples were exposed to water at various temperatures and plugging was found to occur in materials which contained significant quantities of montmorillonite clay. Temperature had little effect on the degree of plugging between 75 and 325 F. The measured permeabilities tended to increase slightly with temperature, but the changes were small compared with the initial loss of permeability on wetting. Sequential permeability measurements were made on two samples using air, water, steam, water and air, in that order. Both samples were water-sensitive and plugged extensively after the initial injection of water. Upon exposure to superheated steam, the samples dehydrated and their permeabilities to superheated steam were comparable to those initially measured with air. The remaining measurements with water and air confirmed that the water plugging was reversible and that the samples were not seriously damaged during the tests. INTRODUCTION The swelling of water-sensitive clays during water floods has long been recognized as a potential source of reservoir damage. The recent extensive application of steam injection and stimulation has compounded this problem since both hot water and steam (as well as fresh water at reservoir temperatures) are, at some time, in contact with the producing zone adjacent to the bore of a steam injection well. The purpose of this paper is to present data which compare the sensitivity of some natural sedimentary rock samples to water at various temperatures, and to superheated steam. Some properties of montmorillonite clay are briefly reviewed, and comparisons are drawn between empirical data and the predicted behavior of the montmorillonite known to be present in the samples. PROPERTIES OF MONTMORILLONITE CLAY Water initially adsorbs on dry Na-montmorillonite clay in discrete layers in the interlaminar space between clay platelets. The platelet spacing, which is 9.6 A (angstroms) for a dehydrated clay, has been observed to expand in discrete steps to 12.4, 15.5, 18.4 and 21.4 A spacings, indicating the formation of four discrete layers of regularly oriented water molecules.1 The first two layers are easily formed by hydrating a dry sample to equilibrium in an atmosphere with carefully controlled humidity. The formation of the higher layers is more difficult. The usual X-ray diffraction patterns of the more highly hydrated samples indicate a gradual increase in the average spacing between 15.5 and 19.2 A, followed by a discontinuous expansion to 31 A when the weight ratio of water to dry clay is between 0.5 and 1.2.2 Platelet expansion above 31 A proceeds monotonically as the moisture is increased and no regular arrangement of the platelets is observed. Water-sensitivity in sedimentary rocks is usually associated with Na-montmorillonite clay when it is in the noncrystalline state. Mering3 found that the average lattice spacing of sodium montmorillonite hydrated at 68 F and 70 per cent relative humidity was 15.5 A, and that the spacing. at 92 per cent humidity was 16.5 A. The water adsorbed at the higher humidity has the same free energy as liquid water at 65.6 F. Kolaian and Low4 used a tensiometer to measure the thermodynamic properties of water in diffuse suspensions of montmorillonite clays relative to pure water. They observed that water in suspensions as dilute as 6 per cent clay became partially oriented when left undisturbed. The bonding associated with this orientation was not extensive because the free energy difference between the water in suspension and pure water was only a few millicalories per mole. They also found that the measured free energy difference decreased rapidly with temperature and became negligible above 100 F. This evidence indicates that montmorillonites contained in sedimentary rocks would dehydrate to a crystalline structure when exposed to superheated steam, and that the rock permeability measured with steam would be equivalent to that measured with air.

The Use of Salt Cement Blends as an Aid to Better Cementing in Formations Containing Fresh Water Sensitive Clays

Abstract The application of salt for primary cementing in Western Canada has been restricted largely to salt cavern storage wells and to the development of potash reserves in south-central Saskatchewan. The value of salt cement blendsin cementing through fresh water sensitive formations has recently broughtabout wide usage of this technique in certain areas of the United States, andthere is good reason to believe that there are several areas in Canada wherethe success of primary cementing could be improved by the use of saltcements. There has been considerable work done on the applicability of salt cement, with emphasis on improved cement-formation bonding and the minimization offormation deterioration by water contact. Field results have shown that saltcements have improved the success of primary and squeeze cementing jobs. Laboratory work has been done to evaluate the change in slurry properties with the addition of varying concentrations of salt to commonly used cementing blends. Introduction The use of salt cements in Canada has been quite limited and, as a result, the primary purpose of the information presented here is to illustrate theadvantage of salt for primary cementing of oil and gas wells where the formations encountered contain fresh water sensitive clays and shales. The first known use of salt cements in Western Canada occurred within thepast ten years. Initially, salt cements came into use because of the failure toset fresh water cement abandonment plugs in the salt and potash zonesencountered in potash test holes. Earlier experience in the U.S.A. proved that a good cement-formation bond through a salt section could only be achieved byusing a salt cement. Figure 1 illustrates the bonding of cement to rocksalt. The illustration shows how a fresh water slurry will dissolve a portionof the salt, with the result that there is no bond between the salt and cement, while the saturated salt slurry does not dissolve any portion of the salt, resulting in good contact and bonding between the salt and the cement. Operators in Saskatchewan found that casing could be cemented successfully in salt cavern gas storage wells with a sodium chloride slurry; more recentwork has employed a sodium chloride and potassium chloride (potash) saturated slurry (1). Later, casing was set into the potash for a solution mining project, and again salt cements were used to obtain a good primary cement job.