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    Understanding Unconventional Gas Reservoir DamagesG. M. S. Lucas, E. M. Moura, A. R. de Andrade, Baker Hughes Incorporated; R. B. Z. L. Moreno, UNICAMP

    Copyright 2011, Offshore Technology Conference

    This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 46 October 2011.

    This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

    AbstractIt is estimated that there are large reserves of unconventional gas located throughout the world, including coalbed methane,

    shale gas and tight gas sands. Due to their specific characteristicsparticularly low permeability in the microdarcy range,microfractures and high capillary pressuresunconventional gas reservoirs are vulnerable to irreversible damage during ex-ploitation. This paper focuses on studies of damage evaluation in unconventional gas reservoirs around the world. We aim to

    provide a set of guidelines to avoid, minimize and/or remediate this damage.

    In Brazil, the Petrobras Strategic Plan for 2020 predicts 200% growth in gas production until 2020, as compared to 2010

    gas production. Expected growth in international gas production will be 30% until 2020, as compared to 2010 world gas pro-

    duction. The main natural gas production projects of Petrobras between 2010 and 2014 are Mexilho, Urugu and Tamba

    Cidade de Santos, totaling 35,000 BOE per day. Demand for natural gas is expected to increase from 46 million m 3/day

    (2009) to 130 million m3/day until 2014, envisaging use in electrical power, industrial, fertilizer and other applications.

    The fundamental processes causing formation damage include but are not limited to physicochemical, chemical, hydro-

    dynamic, mechanical, thermal and biological. Formation damage is not necessarily reversible, and therefore it should be

    avoided. Laboratory tests are designed to determine, understand and quantify the governing processes, their dependency on

    the in-situ and operational conditions, and their effect on formation damage.

    It should be emphasized that on one hand, high capillary pressure favors the spontaneous imbibition phenomenon and,consequently, mainly water-blocking damage. On the other hand this same effect has been investigated by several researchers

    to change the reservoir wettability by optimizing rock-fluid interactions using specific surfactant-brine systems during exploi-

    tation. It has been concluded that, beyond formation evaluation, phenomenological observations and the optimization of rock-

    fluid interactions are likely to promote gas production from minimally damaged unconventional reservoirs.

    IntroductionReservoirs that originally contain free gas as the only hydrocarbon source are termed gas reservoirs. These reservoirs store a

    mixture of hydrocarbon compounds that exist entirely in the gaseous state. The gas may be dry, wet, or condensate,depending on its composition, as well as the pressure and temperature at which the accumulation occured 1. A natural-gas

    source is named an unconventional gas reservoir when the well must be stimulated by large hydraulic fracture treatment, ho-

    rizontal wellbores or multilateral wellbores to produce at economic flow rates or volumes 2.

    Similar to conventional hydrocarbon sources, unconventional gas reservoirs present complex geological characteristics, as

    well as heterogeneities at all scales. Unconventional gas reservoirs, though, typically have very fine-grain rock size distribu-tion, gas storage and flow regimes influenced by the tight pore throat. Grain rock size distribution and organic and clay con-

    tent can promote favorable bonds between the gas molecules and the rock surface3. The three major categories of unconven-

    tional gas reservoirs are coalbed methane, tight gas sands and shale gas2.

    In terms of pore structure, shale gas reservoirs typically present dimensions at the nanometer to micrometer size, while

    tight gas sands present pores in the micrometer or larger size 3. Coalbed methane systems are naturally fractured and can

    present two distinct porosity patterns: one primary composed of micropores with extremely low permeability; and one sec-

    ondary composed of macropores with a natural fracture network of cracks and fissures 1. One important aspect to consider for

    unconventional gas reservoirs due to their lower permeability in contrast to high permeability reservoirs, is that the effects of

    capillary pressure are significant4,5. All these characteristics make unconventional gas reservoirs more susceptible to damage

    during exploratory phases and processes6.

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    Formation damage is a generic term. It relates to the permeability reduction of a reservoir due to a series of adverse

    processes. It is an undesirable subsurface operational and economical problem that can occur during different phases of oil

    and gas exploitation. These phases include drilling, cementing, completion and workover, gravel packing stimulation, pro-

    duction and injection operations. Formation damage can be caused by many factors such as physicochemical, chemical, bio-

    logical, hydrodynamic, thermal and mechanical. The damage can result in permeability impairment, skin damage and reduced

    well performance. Formation damage is not necessarily reversible, and therefore it should be avoided 7.

    Modeling formation damage, based on careful laboratory and field experiments, can provide a scientific basis for devel-

    oping strategies to avoid, or at least minimize its occurrence. Designing the right analytical and experimental techniques aswell as using the correct modeling approaches and simulations can help the diagnosis, evaluation, prevention, remediation

    and control of formation damage in oil and gas reservoirs7.

    The objective of this present work is to identify the principal mechanisms of unconventional gas reservoir damage, consi-

    dering the immediate Brazilian and world scenarios. The ultimate goal is to develop fundamental well guidance that mini-

    mizes impacts on reservoir performance arising from exploitation operations. For this, this paper seeks to develop a consoli-

    dated and fundamental experimental methodology.

    State of The ArtThe fundamental processes responsible for formation damage include, but are not limited to: physicochemical, chemical, hy-

    drodynamic, mechanical, thermal, and biological. Moreover, different mechanisms can contribute to formation damage. Iden-

    tification of these mechanisms is important to execute an efficient strategy of remediation to minimize damages. As empha-

    sized by Civan7, the most frequent formation damage mechanisms can be classified into two basic groups: (1) fluid-fluid inte-

    ractionsemulsion blocking, inorganic and organic depositions, and (2) fluid-rock-particle interactionsmobilization, mi-gration and deposition of fine particles, changes on formation surface chemistry and changes in porous media structure.

    In a general way, the lab tests play a strategic role in improving knowledge about reservoir damage as well as predicting it

    by means of more realistic modeling. According to Civan7, the use of current models for formation damage analysis and

    management has been limited due to the difficulties in understanding and implementing them. This can be attributed to the

    assumption of a single-fluid phase and a predominate mechanism of mobilization, migration and retention of fine particles in

    a porous media.

    X-ray diffraction (XRD) and scanning electronic microscopy (SEM), coupled with energy dispersive spectroscopy (EDS),

    are analytical techniques applied to determine bulk rock composition. These provide qualitative and quantitative analysis in

    terms of silica, calcite and dolomite composition, for example. The analysis of mercury penetration can be used to evaluate

    important parameters, such as average pore throat radius for the reservoir, median value of pore throat radius, injection effi-

    ciency, the nonmercury saturation under a pressure differential, etc6. Atomic force microscopy (AFM) is an important tech-

    nique for exploring the interactions governing rock-fluid systems present during the processes of formation damage 8.

    Computerized tomography (CT) is a tool that has been used to perform image analysis of fluid saturation during dis-

    placements. CT measures the X-ray linear saturation. The core can be imaged dry or fully brine saturated. A linear relationbetween these endpoints establishes the fluid saturation at intermediate saturations. For core flow studies, the brine should be

    doped with 8% KI to increase the X-ray attenuation contrast between gas and the brine 9.

    Formation damage can be studied in the laboratory by return permeameter devices, which simulate the in-situ conditions

    in a controlled environment. This is done to evaluate, step-by-step, different parameters that can result in formation damage.

    This apparatus is also able to test remediation systems when the chemical treatment is assumed as an alternative. Test results

    are often given as percent return permeability, which is the percentage of the original permeability retained by the core after

    exposure to the test fluid10. Typical testing systems include core holders, fluid reservoirs, pumps, flow meters, sample collec-

    tors, temperature control systems, pressure transducers and data acquisition systems (Fig. 1).The degree of sophistication in

    the design of the core test apparatus depends on requirements of the objectives, conditions and expectations. To perform la-

    boratory core flow tests a set of information should be established/provided 7, as follows:

    The selection of representative samples, including fluids and core samplesthe objective is to investigate severalfluid-fluid and rock-fluid interactions. The compositions of fluids should be identified, for example the brine com-

    position, considering both formation and injection system. The core samples should be preserved, so as to minimizepossible changes on surface chemistry.

    Test conditions should be as near as possible to in-situ conditionsall field operations should be considered, such asdrilling, completion, stimulation, and production strategies and techniques.

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    Fig. 1Schematic representation of a typical return permeameter device

    One very important caution by Sharma et al.11states that if the core properties are altered relative to the reservoir, then the

    predictions based on core analysis will be of little value. It is known that wettability has a major impact on multiphase flow in

    porous media. All core analysis to predict multiphase behavior should be performed on core samples with the correct wetta-

    bility. They concluded that drilling-fluids components considered bland can alter the rock wettability and permeability.According Civan7, most core flow tests are carried out by horizontal core plugs because Darcys law does not include the

    gravity effect, and the analytical derivations used for interpreting the experimental data are simplified. As multiphase fluid

    systems with significantly different properties and particulate suspensions are flowed through the core plugs, it complicates

    the mathematical solution of the governing equations necessary for experimental data interpretation. If the fluid densities are

    significantly different, then core flow tests using vertical plugs are recommended and gravity effects should be considered.

    Among the tensoatives typically evaluated in formation damage studies to unconventional gas reservoirs are fluorosilanes,

    amines (oil-soluble and water-soluble), cationic surfactants, aliphatic ethoxylates, fluorinated surfactants and fluorinated po-

    lymers12. Physicochemical properties of tensoatives applied in the study should be evaluated, including the following parame-

    ter characterizations: hydrophile-lipophile balance (HLB), surface tension, critical micelle concentration (CMC), specific

    surface area, Krafft point, viscosity, adsorption, density, ion vibration potential, electrical conductivity, among others. The

    knowledge of these properties can help optimize the tensoative action. For this activity, different techniques can be applied:

    interfacial tensiometry (capillary rise, pendant drop or Du Noy ring, for instance), Langmuir trough, ultraviolet-visible (UV-

    Vis) spectroscopy, viscosimetry, electroacoustic spectrometry, conductivimetry, etc.Regarding the rock-fluid mechanisms of formation damage, it is known that the chemical reactions involved between the

    fluids (from the different operation processes) and porous media are responsible for the more complex forms of formation

    damage10. Clay minerals can be highly reactive with drilling fluids, so formation damage is more likely in clay-bearing clas-

    tic rocks, such as in the majority of unconventional gas reservoirs. In addition, microfractures present in unconventional gas

    reservoirs facilitate formation damage due to stress sensitivity.

    The following section discusses state-of-the-art studies regarding formation damage in the three unconventional gas re-

    servoir types discussed by this overview: coalbed methane, tight gas sandstones and shale gas.

    Coalbed Methane.The main characteristic that distinguishes coalbed reservoirs from conventional reservoirs (sandstones

    and carbonates) is that coal can typically generate its own hydrocarbons. An outside source is not necessary because coal is

    an organic-rich source rock13. Coalbed methane reservoirs are originally sedimentary rocks that contain more than 50% by

    weight organic matter, consisting mainly of carbon, hydrogen and oxygen, and resident moisture1. These reservoirs are natu-

    rally fractured and are characterized by two distinct porosity systems (Fig. 2),or dual porosity systems1,13.

    Primary porosity systemmicropores with extremely low permeability. Substantial quantities of gas may be ad-sorbed on its large internal surface area and can flow through the primary porosity system by a diffusion process.

    Secondary porosity systemmacropores, or cleats, originating from the natural fracture network of cracks and fis-sures inherent in all coals, act as a sink to the primary porosity system and provide the permeability for fluid flow.

    According Tarek1and Len13, fracture systems from tectonic activities may also be present, which can increase the

    coal's permeability.

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    Fig. 2Schematic representation of the two distinct porosity systems in coalbed reservoirs1

    The gas-in-place, typically a mixture of C1, C2, traces of C3, and heavier N2and CO2, is adsorbed on coal surfaces of the

    primary porosity system and is considered a near liquid-like state as opposed to a free-gas phase. The cleats are primarily

    saturated with water, which must be removed (produced) to lower the reservoir pressure and release the (desorbed) gas fromthe micropores1. According to Len et al.13, production from wet coalbed reservoirs is often associated with significant

    amounts of water production.

    As stated by Tarek1, the economical development of coalbed methane reservoirs depends on: (1) a sufficient amount of

    adsorbed gas (stored gas); (2) an adequate permeability and porosity system; (3) enough pressure for adequate gas storage

    capacity; and (4) desorption time that permits economic gas production. Most coalbed methane reservoirs require:

    Hydraulic fracture stimulation to supplement the coal cleats and to interconnect the cleat system to the wellbore

    Artificial lift of the water from coal cleat system

    Water disposal facilities

    Complete well pattern development

    Coal is formed from a variety of chemical, mechanical and biological mechanisms acting on sedimentary organic matter,

    known as the coalification process. Coal rank is an important property established by the American Society for Testing and

    Materials (ASTM) that corresponds to the degree of physical and chemical alteration that has occurred during the coalifica-tion process on coal structure and composition. The longer the coalification process, the higher rank the coal becomes 13. Coal

    rank analysis can quantify the moisture content, ash content, volatile matter, fixed sulfur content, fixed carbon content and

    the calorific value of the coal14. According to Barr14, the coal rank enables insight into the coal strength, permeability, water

    sensitivity, density and surface area, which are important characteristics for studying formation damage, as well optimizing a

    fluid system.

    Coalbed methane reservoir productivity is routinely improved by hydraulic fracturing using proppant-laden gelled fluids

    containing polymers, surfactants, friction reducers and other chemicals, which can result in damages due to permeability re-

    duction. Coalbed methane reservoirs normally contain a certain amount of clay components, such as smectite, illite, kaolinite,

    calcite, chlorite, etc. They can be affected by the invasion of incompatible water-based fracturing fluids and generate irre-

    versible formation damage from matrix swelling and cleat plugging15.

    Chen et al.15investigated the impact of gel fracture fluids on coal seam permeability and the performance of some surfac-

    tants in reducing permeability impairment and improving gel cleanup. They applied different techniques to evaluate the sur-

    factant impact, such as: (1) the sessile drop method for estimating wetting properties of solid surface and liquid systems by

    measuring the contact angle and the surface tension; and (2) core flow system to evaluate the effect of different fracture flu-

    ids. They concluded that linear and cross-linked gel could damage the coal samples, and the addition of a surfactant to a

    cross-linked gel had little effect on improving the cleanup of the residual polymer-based fracturing fluids.

    Goktas and Ertekin16stated that polymer-based and gelled fracture fluids may cause significant formation damage in coal

    seams, with permeability reduction up to 10% of its original value. In addition, throughout the extent of the formation dam-

    age into the coal seam the performance of the fracture becomes as low as that of the regular wellbore. Coal seams are mar-

    kedly anisotropic reservoirs.

    Tight Gas Sandstones.Due to the increasing price of gas in world markets, the petroleum industries have paid more atten-

    tion to non-conventional gas reserves especially tight gas reservoirs. This kind of reservoir is characterized by low permeabil-

    itynormally combined with significant porosity and high pore pressureand is able to accumulate a high gas content17.When compared to medium- and high-permeability gas reservoirs, tight gas reservoirs show characteristics of smaller pore

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    throat, water wet and strong water imbibition effects. This makes them more susceptible to damage during drilling, comple-

    tion, production and stimulation operations, and increases the chances of productivity loss. Even if the operational conditions

    are underbalanced (reservoir pressure greater than hydrostatic pressure), there will be a potential risk of tight gas reservoir

    damage6. One important characteristic of low-permeability formations, in relation to high-permeability formations, is that the

    effects of capillary pressure (Pc) are significant6-5. In a gas well the capillary pressure represents the pressure drop in water-

    gas interface and can be expressed by the Young-Laplace equation, as presented in Eq. 1 below:

    (Eq. 1)

    Where: is the liquid-gas interface tension or surface tension (mN/m); is the water-solid contact angle (degrees); and

    Rmis the mean radius of curvature of the water-gas interface (cm). The magnitude of capillary pressure increases as the per-

    meability decreases. The increasing capillary pressure, at the same water saturation, with decreasing permeability is a func-

    tion of the decrease in the mean radius of curvature (Rm). The intrusion of water into tight formations can effectively reduce

    pore size due to clay swelling and fines migration. Normal relative gas permeability at 60% water saturation is ~0.356. The

    increase in capillary pressure due to water-blocking damage can be estimated from J function relationship presented in Eq. 2,

    as follow:

    (Eq. 2)

    Where: J(SW) is Leveretts J function (a dimensionless unit tied to water saturation, typically between 1 and 7, with highernumbers indicating lower saturation), is the effective formation permeability (md), and is the fractional porosity. This last

    equation makes easier the perception that as closer to 90 is, that is, as the reservoir becomes more nonwet, the capillary

    pressure tends to reach zero. Thus, the minimum capillary pressure could be obtained, theoretically, when =90 . The capil-

    lary pressure effect can support the imbibition effect of fluids and, consequently, it causes formation damage during the dif-

    ferent stages of exploitation of a tight gas reservoir. This same effect, though, has been the target of much research6-12 on the

    action of surfactants improving wettability conditions, aiming for maximum gas recovery.

    Wettability is clearly a property of the whole system. It is necessary to specify the characteristics of all three phases

    present in the reservoir to understand the behavior determined by the interplay of the interaction forces between the differentphases and their individual components. Tight gas reservoir wettability depends on rock mineralogy, gas and brine composi-

    tions. Core wettability is traditionally measured by the Amott wettability index. The Amott index to water (I w) is presented in

    Eq. 3 below:

    (Eq. 3)

    Where: Sws is saturation change of core sample by spontaneous imbibition, and Swtindicate the total displacement of

    water.

    Formation damage studies can be carried out by means of spontaneous imbibition tests. There are a wide variety of tests

    to evaluate spontaneous imbibition through different experimental devices that can be easily manufactured. Golman et al.18

    developed a methodology to measure spontaneous imbibition in sandstones samples (Fig. 3). Despite the simplicity of these

    tests, they can estimate especially important damage, mainly regarding rock-fluid interaction. Using these simple tests in ini-tial studies for this type of phenomenon can result in time savings and better work results.

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    Fig. 3Schematic representation of a spontaneous imbibition test18

    Penny et al.5observed by experiments in horizontal sand columns treated with surfactant solutions, that the oil-flow rate

    can be significantly affected by wettability changes. For the water-wet sands ( ~0 ) they obtained a mean rate of 1.8 mL/min,

    while for the non-wet sands ( =90 ) they obtained a mean rate of 4.0 mL/min. The relative permeability to oil varied from

    0.25 (to the water-wet sands), decreasing to 0.13 (to the oil wet sands), and increasing to 0.75 (to the nonwet sands). The

    nonwet sands showed mean values of fractional water saturation lower (~0.18) than those for water-wet sands (~0.45). These

    phenomena are valid for both gas and oil reservoirs of low permeability, in which the pore size distribution is close to the

    micro and submicrometer dimensions.

    The fractures in tight gas sandstone are mainly tectogenetic, in other words, their development is influenced by tectonic

    deformation intensity and fault development. The microfractures are the channels connecting the pore spaces of low permea-

    bility sandstone and have extremely important contribution to the gas filtration in tight sandstone gas reservoirs. During ex-

    ploitation of low-permeability sandstone gas reservoirs, the fracture is easily damaged and difficult to recover 6.

    Another characteristic of tight gas sandstone is that the grain particle surfaces may be covered by clay minerals, resulting

    in pore space reduction, pore throat thinning reduced reservoir permeability and increased irreducible water saturation. Low-

    permeability sandstone reservoirs are often exhibit water saturations less than irreducible water saturation6.

    Therefore, the principal kinds of damage in tight gas reservoirs during water-based underbalanced drilling are:

    Stress sensitivity damage - The pore space in tight sandstone reservoirs is connected basically by microfractures. Af-

    ter the microfracture closes under the effective stress action, the reservoir filtration capability decreases greatly. Inaddition, the closed fracture is difficult to open after the effective stress release 6.

    Water-blocking damage - Under the original condition, tight gas reservoirs often have the state of sub-irreduciblewater saturation. After the reservoir is opened by water-based drilling fluid, the reservoir will intensively suck water

    under the positive pressure differential and capillary force, resulting in water-blocking damage6.

    Abrams9observed, by means of laboratory tests, that water blocking occurs if the drawdown pressure at the fracture face

    does not exceed the capillary pressure by several hundred psi.

    Another area that must be evaluated when drilling underbalanced with water-based drilling fluids in tight gas reservoirs is

    the stress sensitivity as suggested by the following laboratory tests:

    Fracture visualization by advanced stereomicroscope Evaluation of fracture mechanics width by capillary flow porometer (CFP)

    Evaluation of effective filtration throat size distribution of matrix by CFP

    Evaluation techniques of water-phase countercurrent imbibition damage have been applied by Petrobras 19-20, as well as

    other researchers6. It is known that even during water-based underbalanced drilling of tight gas reservoirs, imbibition effect

    can occur, making this kind of study significant. In fact, nowadays these studies have been receiving more attention, but im-

    bibition experiments are still few6. The experimental procedure can follow the steps presented below:

    Select a typical core sample of a tight gas reservoir in the study area. Clean, dry and accurately measure dry weight.

    Select outcrop samples with similar perm-porous properties.

    Establish the initial water saturation of the cores. Set the experimental parameters such imbibition time, underbalanced pressure, and effective stress.

    Shale Gas.Shale gas reservoirs are characterized by features such as extremely low permeability of the rock, high organic

    and clay content, fine grain size and plate-like microporosity21. According Sondergeld et al.3, clay and organic content in gas

    shale reservoirs are able to impart an anisotropic fabric, which affects their mechanical properties. Gas shale reservoir pore

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    structures have dimensions in the range of microns to nanometers. Clay and organic content contribute to gas molecule ad-

    sorption on the rock surface. The fractions of adsorbed gas and free gas are related to organic matter content, pore size distri-

    bution, mineralogy, diagenesis, rock texture, and in-situ conditions (temperature and pressure). As stated by Sondergeld et

    al.3, they have defined as unconventional gas reservoirs only those systems with a sorbed gas component, which includes gas

    shale, coalbed methane and hydrates. Tight gas sands are not included.

    One important issue emphasized by Sondergeld et al.3 is the lack of standardized lab methods for shale gas systems,

    which contributes to the measurement discrepancies.

    Mineralogy plays a significant role regarding shale gas reservoir production. Methods to quantify mineralogy include3

    : XRD (X-ray diffraction)to determine primary mineralogy, although generally overestimates the quartz content in

    clay rich systems if clay is not previously removed;

    FTIR (Fourier transform infrared transmission) spectroscopy - to determine primary mineralogy, but without the in-convenient step of extracting clay from the sample;

    XRF (X-ray fluorescence)to determine the mineralogy by quantifying the elemental abundances stoichiometrical-ly apportioned to common minerals and without overestimating the quartz content.

    The total organic carbon (TOC) can be measured by means of two analytical methods (Leco TOC and Rock Eval) or ob-

    tained from logging tools, but the last are much more subject to misinterpretation due to the characteristic compositional he-

    terogeneity of these reservoirs. In fact, all of the logging tool responsesincluding natural gamma ray, total gamma ray, bulkdensity, acoustic, neutron and resistivityrequire rock-to-log calibration for validation3.

    There are several techniques and methodologies to measure the porosity in gas shale samples, and some factors can affect

    the validity of these measurements, as listed below3:

    Irreducible water due to capillary and clay bounds, as well liquid hydrocarbon from the pore system Extremely low permeability can deter the penetration of gas (helium, nitrogen, methane) and liquid (Hg, water)

    Adsorption effects

    Sample size, crushing methods, and crushed sample weight

    Effect of pore pressure and net overburden stress on microfractures (natural and coring induced)

    Accurate permeability measurement during lab tests is a challenge to the damage study in gas shale samples. This is

    mainly because even after controlling all relevant parameters there is no guarantee that it will be possible to obtain reproduci-

    ble analysis. According Sondergeld et al.3, there are three typical techniques for measuring permeability in shale gas samples:

    pressure pulse decay, pressure decay and steady state. The first two are preferred for ultra-low permeability rocks and can be

    applied at various combinations of confining and pore pressures.

    Shale gas formations are fracture stimulated to extend the drainage radius by creating a long fracture system, connecting

    natural fractures and increasing flow channels to the wellbore. However, most of the fracturing pad fluid leaks off into natural

    fractures, resulting in shorter effective fracture lengths and a damage zone surrounding the fractures 22. Paktinat et al.22tested

    different conventional surfactants and a microemulsion fluid system by lab tests. They wanted to compare their performance

    in terms of leak off and wettability alteration, by means of a 6-ft shale-packed column. They concluded that the microemul-

    sion fluid system is more effective than conventional surfactants for reducing capillary pressure and eliminating phase trap-

    ping in hydraulic fractures. Andrei et al.21evaluated a microemulsion fluid system by using a Canadian shale/sand column,

    and observed that the permeability regain was improved after the cleanup treatment.

    Similar to tight gas sands, shale gas systems can have their hydrocarbon production optimized when the wettability is in-

    termediate, or the contact angle is near 90 because, theoretically, the minimum capillary pressure could be obtained around

    this condition6. Rickman et al.6 stated that the fluid design for a shale gas reservoir containing surfactants should be pre-

    evaluated in terms of reduction potential of interface tension, aiming the optimization of the additive loading. Chemical

    treatments constitute an usual practice in shale gas production. Their main role is to increase natural-gas production and load

    recoveries from shale formations21.

    Due to the poor permeability of shale gas reservoirs, and in part to commingled multilayer production effects, well units

    experience long transient periods before experiencing pseudosteady state flow that represents the decline portion of theirlives. Thus, according Tarek1, the initial transient production trend of a well or group of wells is not indicative of the long-

    term decline of the well. This can make it difficult to distinguish the transient production from its pseudosteady state produc-

    tion, thus leading to misinterpretations of decline characteristics or detection of near-wellbore damage.

    ConclusionsThe best practice to prevent formation damage is to perform laboratory tests during the field exploratory phase, in which

    seismic analysis, logging while drilling (LWD) and wireline data, as well as core samples can complement each other to ob-

    tain a broad formation evaluation. This enables reservoir modeling, leading to profitable field development. In addition, tak-

    ing into account that formation damage can occur in different exploratory phases, and many times the preventive philosophy

    is not adopted, a complete history of the well is necessary to properly characterize the formation damage. This kind of cha-

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    racterization is very complex as many aspects should be considered. The relevancy is even more explicit in the case of un-

    conventional gas reservoirs, in which the heterogeneity and the anisotropy are typical characteristics.

    It should be emphasized that, although the high capillary pressure favors the spontaneous imbibition phenomenon, this

    same effect has been investigated by several researchers to change the reservoir wettability by optimizing rock-fluid interac-

    tions using specific surfactant-brine systems during exploitation processes. It has been concluded that, beyond the formation

    evaluation, phenomenological observations combined with the optimization of rock-fluid interactions is likely to promote gas

    production from minimally damaged unconventional reservoirs. Thus, the tensoatives play a fundamental role in the studies

    of formation damage, as they can provide a suitable approach for preventive and remedial treatments.One important aspect emphasized is the lack of standardized lab methods for studying damages in unconventional gas re-

    servoirs. This is believed to be a result of their high level of heterogeneity, which contributes to measurement discrepancies

    and makes characterization much more difficult. This also hampers establishment of best practices to prevent formation dam-

    age.

    References1. Tarek Ahmed, Paul D. McKinney, Unconventional Gas Reservoirs, Advanced Reservoir Engineering, Gulf Professional Pub lishing,

    Burlington, pp. 187-290, 2005.2. Stephen A. Holditch, HusamAdDeen Madani, Global Unconventional Gas It Is There, But Is It Profitable?, Journal of Petroleum

    Technology, SPE, pp. 42-49, December 2010.3. C. H. Sondergeld, K. E. Newsham, J. T. Cominsky, M. C. Rice, C. S. Rai, Petrophysical Considerations in Evaluating and Producing

    Shale Gas Resources, SPE 131768, Pittsburgh, February 2010.4. R. D. Rickman and Omkar Jaripatke, Optimization Microemulsion/Surfactant Packages for Shale and Tight-Gas Reservoirs, SPE

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