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Current simulation technology for naturally fractured reservoirs is based on either the continuum or the discrete-fracture approach. The more commonly used continuum model can simulate complex recovery mechanisms. However, it uses a very simplified representation of the fracture system for calculating effective fracture permeability. The discrete-fracture flow method can handle complex fracture geometry. However, its use has been typically limited to basic flow calculations through a connected fracture system embedded in zero-matrix-permeability rock.We have developed a new technique for estimating the effective permeability of gridblocks used in conventional simulators. The idea behind this technique is to integrate the realism of fracture systems, as captured by discrete-fracture models, with the complexity of the flow calculations offered by continuum models. The end product of developing this technique is an efficient numerical code based on the boundary-element method. This code permits the fracture system to be complex and poorly connected, and it also includes the contribution from flow through the matrix rock. For fluid flow in the matrix rock, the fractures are treated as planar-source distributions. Periodic boundary conditions, for the flow properties, are used for the calculation of the effective permeability of individual gridblocks.We first use a simple fracture system to demonstrate the validity of our method and to evaluate the sensitivity of the results to matrix and fracture properties. We then use fracture statistics data from the Mesaverde sandstone, effective permeability values from our code, and a continuum simulator to calculate tracer-flow patterns for a more realistic system.

The~aboratory methodology for determining critical gas saturation, SgC' m field depletion processes is still uncertain. Through measurements. on low-permeability rocks, we explore some of the key issues affectmg laboratory determination of Sgc. Differences between laboratory depletion and external gasdrive experiments are measured and analyzed. We also investigate the relationship between average Sgc from material balance and true Sgc, source of supersaturation, gas nucleation conditions, and dynamics of gas bubble growth in d~pletion drive experiments. We assess the use of low-bubblepoint Olls to reduce experiment time. Finally, we suggest some improvements to laboratory procedures.

Laboratory determination of residual oil saturation (ROS) in carbonate cores is sometimes uncertain due to wide pore size distribution, core scale heterogeneity, and complex wettability. The values obtained in laboratory tests may vary depending on flow rates, the type of samples (plugs or whole cores), and sample preparation techniques. The purpose of our study is to integrate modern flow visualization technology with conventional laboratory tools to provide a comprehensive picture of waterflood recovery behavior in four carbonate cores. Our data set comprise thin sections; mercury injection; 3–D porosity distribution; oilfloods and waterfloods on cleaned samples; and 3–D flow imaging of miscible floods, oilfloods, and waterfloods on restored state samples. The 3–D Computed Tomography (CT) images allowed us to understand the reasons for decrease in oil saturation observed with increased pressure drop in the corefloods; whether this is due to capillary-end effects, core scale heterogeneity, or actual reduction in ROS. We find that ROS values under field-rate flooding conditions (~ 1 psi/foot, Nc* ~ 10-8, lateral flood) are in the 30%-60% PV range. These ROS values reduce significantly as the pressure gradient applied during the floods is raised from field values to the much higher-pressure gradients sometimes used in laboratory testing (~ 100 psi/ft, Nc ~ 10-6). The carbonate samples with large pore-throat aspect ratios have the largest ROS values and the biggest variation with the pressure drop used in the waterfloods. Introduction ROS from Laboratory Floods. Most of the early laboratory waterfloods reported in the literature were conducted at high flow rates (Rapoport and Leas, 1953) to eliminate the capillary end effect at the outlet of the core sample. This method is still appropriate for very strongly water wet or very strongly oil-wet rocks. In the former case, waterflooding is a strong imbibition process, and we have a well-defined residual oil saturation (ROS) that is constant over a very wide range of flow rates. The ROS decreases only when flow rates become so large (Nc >10%5) that the trapped blobs of oil are mobilized. In the case of strongly oil-wet media, waterflooding is a drainage process. The waterflooded oil is in the form of continuos films, and residual oil saturation is theoretically close to zero. The issue here is one of determining the oil relative permeability at low oil saturation. Many reservoir rocks are now thought to be have intermediate or mixed wettability (Cuiec, 1991). Waterfloods in such systems are potentially a combination of drainage and imbibition. Laboratory measurements become a problem as we may experience a drainage capillary end effect, encouraging use of high rates; and there may also be a rate dependence in the imbibition trapping mechanism, suggesting the use of reservoir rates (Heaviside, 1991). Any decrease in the oil remaining in the core with increase in waterflood rate can be due to reduction in capillary end effects and/or due to change in the microscopic trapping mechanisms. The first factor is a laboratory artifact and does not reflect behavior in the field. The change in microscopic trapping is the true change in ROS and can be exploited by changing field conditions.

Summary Water blocking caused by invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the water-blocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions. The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10,000 PV of gas in each test to mimic near-wellbore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime. The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("water-blocked") region. Cleanup occurs as gas flows past this high liquid-saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput. We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here, evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages. Introduction Poor gas flow performance following well operations such as completions and workovers was recently observed in some wells in a gas field. Loss of aqueous fluids during these operations causes a ring of high water saturation around the wellbore. This can potentially reduce gas flow into the well, and this phenomenon is called "water blocking." The objectives of our work were to assess the impact of water blocking on well deliverability and to evaluate remediation possibilities. Water blocking has been suspected to reduce deliverability of gas reservoirs.1–5 Bennion et al.1 and Cimolai et al.2 assert that water blocking is a problem in which the in-situ water saturation is significantly less than "irreducible" water saturation. They present two field case studies to advocate their claims. The first case study is on the Paddy formation in Central Alberta [k~100 md; f=15%; Sw (in situ)=17%; Swirr (lab) = 43%]. The second is on the Cadomin formation in Alberta [k~1 md; f=5%; Sw (in situ)=20%; Swirr(lab)=52%]. Metheven3 discusses the performance of gas wells in the Frio and Wilcox formations in Texas. His data show that oil-based drilling fluids lead to significant improvements in gas productivity compared to water-based muds or invert emulsions. Laboratory tests indicate return permeability to gas after exposure to muds to be higher for oil-based mud than for water-based mud. Metheven suggests water blocking and vaporization of oil base filtrate by gas production as reasons for these differences at the laboratory as well as field scale. Holditch4 presents a numerical study of formation damage around a hydraulic fracture in a tight gas sand reservoir. He makes an interesting observation that formation damage can increase the capillary pressure of a rock and that this synergetic effect could lead to waterblock problems. Abrams and Vinegar5 use Computed Tomography to image the flow of nitrogen and brine in microdarcy gas sand cores. They claim that water block is unimportant if the drawdown pressure gradient in the region near a hydraulic fracture is on the order of several hundred psi/in. Stimulation using alcohol or surfactants did not significantly improve gas flow in these cores. On the other hand, MacLeod6 claims aqueous stimulation fluids containing alcohol have proven to be highly successful in stimulating gas production from problem wells in sandstone formations. The published literature does not contain a systematic set of laboratory measurements using different fluids and saturation states. There are no data on corefloods exposed to the large pore volumes of gas flow as would be expected in the near-wellbore environment. Also, laboratory data have never been mapped to a wellbore model to evaluate whether the effects seen in the laboratory are important in reducing well deliverability. Our study attempts to address some of these shortcomings. Approach Our approach consists of the following steps:Laboratory gas floods are conducted at ambient conditions to generate Krg vs. PVgas data.The Krg-PVgas curves for reservoir conditions are computed from the laboratory data.A well flow model with a time varying skin to represent the water-blocking region is developed. The permeability of this skin changes as gas flows past it, and is given by the Krg-PVgas curves.Well deliverability calculations are made for different conditions. Laboratory Gas Floods We conducted laboratory experiments on a preserved, composite (three plugs) sandstone sample with the following properties: f=16%, k=14 md, Swi=28%, L=16 cm, PV=30 ml. The experiments consisted of a series of room-condition, constant pressure- drop humidified methane floods of the core sample containing various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states: fully saturated with liquid, and containing liquid and trapped gas. Brine represents the primary fluid in the water-block region; brinemethanol mixtures represent liquids used for remediation; methanol, toluene, and isopropyl alcohol are used as model liquids to help interpret the data. The saturation states represent the potential conditions in the near-wellbore environment. We present only selected aspects of the laboratory work in this paper, and the laboratory data and analyses are discussed in detail in Ref. 7. We also note that toluene was used as a model solvent to validate laboratory data and has no practical significance. Isopropyl alcohol was used as it has been used for stimulation purposes,6 and it provides a reference value for another potential remediation fluid.

Summary Published theoretical and correlative models and extensions developed duringthis study were examined to evaluate the accuracy of predicting airpermeability from mercury-injection data. A recently developed statisticaltechnique, bootstrapping, was used to compare different variables forcorrelation with permeability and to demonstrate that correlations by lithologyor permeability and to demonstrate that correlations by lithology or by fieldoften are not statistically different. Introduction The estimation of matrix air permeability from mercury-injection capillarypressure data is important when routine permeability measurements cannot beperformed (e.g., with drill cuttings or rubble core) or are of questionableaccuracy (e.g., for rocks with microfractures). This study attempts to addressthree issues:Given mercury-injection data on a single rock sample, howaccurately can we expect to estimate its air permeability?Is the degree ofestimation accuracy dependent on the permeability level of the, sample, onlithology, or on the permeability level of the, sample, on lithology, or on theformation?Do some parts of a mercury-injection capillary pressure curvecontain more information on permeability than other parts? To answer thesequestions, correlative and theoretical models in the literature and new modelsdeveloped as part of this work were evaluated by a range of statisticaltechniques. Table 1 lists the databases used in this study. The Swanson, Thompson et al., and tight-gas-sands data sets are part of the publishedliterature. Our own data set comprises a combination of service company andin-house mercury-injection measurements on 158 samples from more than 30 fieldsworldwide. Background Correlative Approach. Swanson and Thomeer have correlated parametersobtained from capillary pressure curves with air parameters obtained fromcapillary pressure curves with air permeability data. Swanson used a databaseof 116 carbonates and permeability data. Swanson used a database of 116carbonates and 203 sandstones from 74 formations to establish a correlation ofair permeability with the maximum of the parameter S nw/Pc. He permeabilitywith the maximum of the parameter S nw/Pc. He presented different correlationsfor sandstones and limestones and presented different correlations forsandstones and limestones and found that one standard error of estimate wasabout a factor of two. Thomeer found similar results in his correlation betweenair permeability and three parameters calculated from mercury-injectionpermeability and three parameters calculated from mercury-injection data. Wallsand Amaefule used Swanson's approach to establish a new correlation for tightgas sands. They said this equation gave more accurate permeability predictionsbelow 10 d. Swanson's correlation was selected for evaluation in this studybecause it is simple, it is based on a length scale that makes good intuitivesense, and an extensive database is available in the literature from Swanson'sand other work. We also examined whether the Swanson-type correlation could beimproved by using different or more information from a capillary pressurecurve. New length scales, based on entry pressure, on the Purcell and Katz-Thompson models, and on the distribution of lengths about the Swansonscale, were compared for this purpose. Theoretical Model Approach. Some of the early theoretical models representeda porous medium by a bundle of capillary tubes but paid no attention to theirregular way in which different capillary sizes are interconnected. Thissimplistic representation made it necessary for these models to containadjustable constants, which had to be varied from sample to sample to forcegood agreement between predicted and measured permeabilities. An example is thewell-known Carman-Kozeny equation, which contains the adjustable"tortuosity" factor. The cut-and-random-rejoin model, introduced by Childs and Collis-George and subsequently modified by Marshall and Millingtonand Quirk, uses an interesting mathematical technique to overcome somedrawbacks of the early bundle-of-capillary-tube models. These authors had goodsuccess with the model. Recently, Katz and Thompson, and Thompson et al. Usedpercolation theory to develop theoretical models to predict air percolationtheory to develop theoretical models to predict air permeability frommercury-injection data. They said that their permeability frommercury-injection data. They said that their theory was valid for essentiallyall porous rock, and that their predictions agreed with experimentalmeasurements within expected predictions agreed with experimental measurementswithin expected errors. The cut-and-random-rejoin and Katz-Thompson models wereevaluated in this study. These models were chosen because they wereconceptually appealing and contained no adjustable parameters. Statistical Tests - Bootstrapping. In the context of this study, thestandard error of estimate is the most important parameter for evaluating acorrelation. It is used to provide the permeability range for a givenconfidence level within which a single prediction will lie. This study providestwo measures of the standard error of estimate for each correlation. The firstis the actual value obtained for the particular data set. The second isobtained by a relatively new technique called bootstrapping. Data sets usuallyare generated by sampling a subset of a larger population. The standard errordetermined from a particular data set depends on the sample set that wasselected. Bootstrapping can be used to determine how different the resultswould have been if a different set of samples from the same population had beenselected. population had been selected. Applications of bootstrapping areillustrated in Figs. 1 through 3, which depict results from performing a linearregression of log 10 ka with log 10 Lmax. The results of the regression arepresented here only to illustrate bootstrapping and are discussed presentedhere only to illustrate bootstrapping and are discussed in detail later. Thelinear regression yields a slope of 1.58 and a standard error of estimate of afactor of 2.8. Fig. 1 shows the range and frequency of values that would beexpected if the linear regression had been performed on 1,000 sample setsbootstrapped from the Chevron data set. The 1,000 bootstrapped sample sets weregenerated by picking 158 samples at random, with replacement, from the original Chevron data set of 158 samples. Replacement allows a particular sample in thedata set to be picked more than once, and hence, many different sets of 158samples can be created from the original data set of the same size. Each solidline in Fig. 2 represents 95 % of the range of values obtained by performinglinear regressions of log 10 ka with log 10 Lmax on 1,000 sample setsbootstrapped from the Chevron data set; the solid lines differ in the randomseed used for bootstrapping. The overlap of the solid lines shows that thespread in the values of the slope and standard error for the boot-strappedsamples is repeatable. Bootstrapping does not rely on the usually unverifiableassumptions of normality and also is not restricted to statistical measuresthat can be manipulated analytically. SPEFE P. 304

We constructed a novel, state-of-the-art laboratory setup that captures several hundred pressure readings per second to study the response of cores to pressure disturbances. We used our new experimental setup to measure accurately and rapidly permeability of homogeneous cores, matrix and fractured properties of a fractured rock, and the individual segment properties of a butted core sample.