bluuebunny/crossref_metadata_2025 huggingface dataset:
Material-Balance Analysis of Gas Reservoirs with Diverse Drive Mechanisms
Authors: Kabir C. S. , Parekh B. , Mustafa M. A.
Published: September 2015

Material-balance (MB) analysis for in-place volume estimation in gas reservoirs has been in practice for decades. Nonlinear responses from geopressure reservoirs with or without aquifer influx present special interpretation challenges. One of the main challenges of in-place volume estimates involves the estimation of average-reservoir pressure with production. To that end, modern pressure sensors installed at bottomhole and/or surface largely help establish a given well's dynamic performance by way of rate-transient analysis.

This paper explores the applicability and limitations of the standard analytical tools in volumetric, geopressure, and waterdrive systems for a diverse array of fluids, from dry gas to near-critical gas/condensate. The systematic approach presented in this paper attempts to increase accuracy in results by ensuring consistency in solutions from multiple methods used to first assess the average-reservoir pressure from production performance data, followed by in-place volume estimation. In this context, we examined analytical tools, such as the pav/z vs. cumulative gas production (Gp) plot, and cumulative reservoir voidage vs. cumulative total expansion plot. Both pot aquifer and unsteady-state Carter-Tracy aquifer models were considered to account for water influx. Besides the use of Cole and drive indices plots, two diagnostic log-log plots are introduced involving total expansivity and change in average-reservoir pressure. In addition, we sought solution objectivity by introducing a diagnostic tool in the Walsh and Yildiz-McEwen MB plots. Both MB methods involve plotting of cumulative reservoir voidage (F) vs. cumulative total expansion (Et), whereas the diagnostic tool consists of plotting F/Et vs. Et on the same graph.

Initially, synthetic data helped us understand the overall system behavior and instilled confidence in the solutions obtained for various combinations of drive mechanisms. Statistical design of experiments prompted us to explore independent variables, such as aquifer-to-hydrocarbon PV ratio, production rate, degree of overpressure, and the aquifer source. Those learnings were validated with published and new field data encompassing an array of reservoirs with various drive mechanisms and fluid type.
Precision Control of Gel Formation Using Superparamagnetic Nanoparticle-Based Heating
Authors: Panthi Krishna , Mohanty Kishore K. , Huh Chun
Published: September 2015

A novel method of generating a polymer gel at a specified location in a subsurface formation was developed by adding superparamagnetic nanoparticles to the gel-forming polymer and heating the polymer by the nanoparticle-based hyperthermia. It blocks only the high permeability zones by highly localized gelling of the polymer employing magnetic hyperthermia heating, so that the oil in the low permeability zone can be recovered. In this paper, the gelling behavior of hydrolyzed polyacrylamide-polyethylenimine (HPAM-PEI), curdlan, methyl cellulose (MC) and hydroxypropyl methylcellulose (HPMC) was studied as a function of temperature and salinity. The effect of adding iron-oxide superparamagnetic nanoparticles (Fe3O4-NP) on gellation was also studied. The elastic and viscous moduli (G′ and G”) of curdlan suspension, and MC and HPMC solutions (with and without Fe3O4-NP) were measured which served as a quantitative measure of the gelling temperature and the gel state. For the curdlan, MC and HPMC boipolymers, the gel formation efficiency is enhanced by the presence of salts, but the presence of Fe3O4-NP does not have significant effect on gel formation.
Design and Interpretation of Transient Tests at Well's Inception
Authors: Hashmi G.M. , Kabir C.S. , Hasan A.R.
Published: September 2015

Operators often avoid conventional drill-stem testing (DST) in offshore environments because it is costly and its value lacks transparency. Short-duration tests may be a promising alternative to conventional DSTs for learning formation conductivity, but they should not be restricted to exploratory wells. Short-duration tests can have a profound impact in any deepwater field-development setting. Stakes are high when unfavorable productivity and injectivity indices may change the well count calculus. Tools such as formation testers provide a credible alternative, but closed-chamber tests (CCT) and/or slug tests are also helpful for situations in which large volumes of formation fluid are sampled.

Given that short-duration tests (CCT and slug) can last only a few minutes—particularly in high-conductivity reservoirs—we approached the challenge with a two-fold strategy. First, we developed a forward model to design the chamber length to ensure that we collected interpretable test data. Second, we combined the CCT and slug tests so that we could control the total test duration, particularly in high-conductivity reservoirs. The approach presented here allowed individual treatment of slug, CCT, and reverse-slug or injection test for underpressured reservoirs. Overall, the model presents a simple, yet complete approach to design and analysis of these short-term tests.
Improving Reservoir Forecasts by Understanding the Relative Impacts of Sparse Data, Reservoir Modeling Workflow and Parameter Selection, and Human Bias
Authors: Meddaugh W. Scott
Published: September 2015

Nandurdikar and Wallace's (2011) review of nearly 150 major capital projects showed that the industry is actually delivering only 75% of the production volumes forecast at the time of project sanction overall and those projects with identified subsurface issues delivered only 55% of the forecast volumes. In other words, the industry production forecasts are significantly optimistic. There are a variety of factors that contribute to the optimistic forecasts. The most important are areal subsurface model grid size, well location optimization workflows, sparse data bias, and “pro-project sanction” management bias. Each of these individually may contribute on the order of 10-25% or so of the observed overall forecast optimism. The impact of other factors such as stochastic model parameters (e.g. semivariogram range) and vertical upscaling are significantly less important.
Compositional Variation in SAGD
Authors: Ghasemi M. , Whitson C. H.
Published: September 2015

In last two decades, the steam assisted gravity drainage (SAGD) has been successfully implemented for increasing the oil recovery from bitumen reservoirs (Butler et al. 1981, Butler and Stephens 1981). This paper describes a detailed study of compositional variation in a SAGD process.

A series of 2D numerical simulations are conducted based on the generic Athabasca type reservoirs. The fluid model provided in this study developed from an extensive work on the experimental analysis and fluid characterization modeling of the Athabasca and light solvent mixtures. In the equation of state (EOS) model, Bitumen is represented by 5 pseudo-fractions ranging from light, medium and heavy to extra-heavy components. Moreover the steam based Kvalues of bitumen fraction is developed and considered in this study.

The change in the compositional variation in the edge oil-flow zone are briefly studied in this work. Based on the analysis of compositional variation, we found the presence of vaporizing-condensing mechanism (VCM) as the second order effect that helps to increase the oil recovery from a SAGD process. The viscosity profile at the edge oil-flow zone and at the residual oil behind the interface is changed when the VCM is presented. The VCM effect can be more significant if the SAGD process is examined under different type of heavy oil and bitumen samples. The effect of the oil viscosity heterogeneity (the oil viscosity increases with depth) on the performance of SAGD process is studied. The assumption of uniform oil viscosity throughout the bitumen (heavy oil) reservoir may not be representative of the measured oil viscosity in the field. The presence of the highly nonlinear vertical composition and fluid viscosity gradient in bitumen deposits is mainly due to severely biodegraded oils. Extensive degradation creates a highly nonlinear vertical viscosity variation with a large viscosity gradient at the bottom of the formation. We develop an empirical correlation which account for the nonlinearity of the viscosity variation versus depth.

The novel of this present work is introducing VCM as the second mechanism which has second order effect in increasing heavy oil recovery. Lack of accurate EOS model or inadequate number of pseudo components in the EOS model may neglect the VCM term and lead to underestimate the ultimate oil recovery e.g. ~10% of oil recovery is only gained by VCM for heavy oil with API of 14.

The Effect of Bitumen characterization and viscosity heterogeneity in a SAGD process is extensively studied in this work. Moreover, the results show that the effect of VCM in increasing oil recovery for the viscosity gradient reservoir is even more significant compared with the homogeneous viscosity. Certainly, the results of this work is essential to understand the true physics of the SAGD process in the compositional variation of the heavy oil reservoirs.
Foams with Wettability-Altering Capabilities for Oil-Wet Carbonates: A Synergistic Approach
Authors: Singh Robin , Mohanty Kishore K.
Published: September 2015

The goal of this work is to systematically study the effect of wettability alteration and foaming, either acting individually or synergistically, on tertiary oil recovery in oil-wet carbonate cores. Three types of anionic surfactant formulations were used: alkyl propoxy sulfate (APS), which exhibited low interfacial tension (IFT), wettability alteration (WA), and weak foaming; alpha-olefin sulfonate (AOS), which showed no WA, but good foaming; a blend of APS, AOS and a zwitterionic foam booster, which showed low IFT, WA and good foaming. First, contact angle experiments were conducted on oil-wet calcite plates to evaluate their wettability altering capabilities. Second, spontaneous imbibitions in a microchannel were performed to study the role of IFT- reduction and wettability-alteration by these formulations. Third, static foam tests were conducted to evaluate their foaming performance in bulk. Fourth, foam flow experiments were conducted in cores to evaluate potential synergism between the anionic surfactant alpha-olefin sulfonate and the zwitterionic surfactants in stabilizing foam in the absence of crude oil. Finally, oil displacement experiments were performed using a vuggy, oil-wet, dolomite core saturated with a crude oil. After secondary water floods, surfactant solutions were coinjected with methane gas at a fixed foam quality (gas volume fraction). Contact angle and spontaneous imbibition experiments showed that AOS can act as a wettability-altering surfactant in the presence of sodium carbonate, but not alone. No synergy was observed in foam stabilization via the blend of zwitterionic surfactant and alpha-olefin sulfonate solution (1:1) in a water-wet carbonate core. Oil displacement experiment in oil-wet carbonate core revealed that coinjection of wettability-altering surfactant and gas can recover significant amount of oil (33% OOIP) over waterflood. During foam flooding, with AOS as the foaming agent, only a weak foam was propagated in a carbonate core, irrespective of the core wettability. A blend of wettability-altering surfactant, AOS and zwitterionic surfactant not only altered the wettability of carbonate core from oil-wet to water-wet, but also significantly increased the foam resistance factor in the presence of crude oil.
Analysis of Drawdown Sensitivity in Shale Reservoirs Using Coupled-Geomechanics Models
Authors: Wilson Kurt
Published: September 2015

Productivity loss in some shale reservoirs is often attributed geomechanics-related factors, even when the exact mechanism(s) is undetermined. Overpressured reservoirs tend to experience a large increase in effective stress during depletion, which can contribute to a dramatic loss in fracture conductivity. Factors such as a low elastic modulus may also contribute to productivity loss through processes such as proppant embedment. The Haynesville Shale (Texas and Louisiana) is often cited as an example of geomechanics-related productivity loss since it is characterized by high overpressure (1.0 psi/ft in some areas) resulting in extremely high initial production rates followed by steep declines.

In this study, a simplified, single-fracture coupled model with different orientations relative to the principal stresses is used to investigate the impact of drawdown management on estimated ultimate recovery (EUR). The coupled-geomechanics reservoir simulation model was constructed using a comprehensive set of logs, rock mechanics tests and fracture conductivity measurements from a shale reservoir. In particular, various drawdown schedules (bottomhole pressure vs. time) and their effect on effective stress on the fractures were compared. Subsequently, fracture conductivity (Fc) relationships considering the maximum effective stress for each drawdown scenario were constructed and used in traditional (non-coupled) reservoir simulations to forecast gas EUR.

It was found that a managed drawdown schedule can improve EUR by up to 15%, mainly by reducing the effective stress on unpropped fracture regions. Importantly, the modelling results show that unpropped fracture “pinch points” near the wellbore may lead to very significant reduction in overall recovery. Model results showed that even proppant concentrations around 0.3 lb/ft2 maintained sufficient conductivity to not hamper well productivity in nanodarcy reservoirs. Traditional reservoir simulation approaches using compaction tables (pore pressure vs. Fc) lack the critical process of stress path dependency that governs the effective stress on the fractures and is necessary to adequately model this system.

Future experimental work should be directed at measuring unpropped fracture conductivity at high stresses and longer durations (creep) as unpropped fractures appear to be a main contributor to the observed geomechanical-related productivity loss.
A Novel Solution for Performing Real-Time Fiber Optic Temperature Measurements
Authors: Barry Alexander , Broaddus David , Ivasauskas Jonas , Johnston William
Published: September 2015

As Operators are increasingly seeing the value of in-well monitoring in optimizing production and reducing interventions, Operators are demanding greater accuracy, reliabilty and timeliness of well information above what is available today.

This study explores a new method of measuring temperatures in harsh downhole environments that aims to improve on some of the limitations of conventional distributed temperature sensing (DTS). Instead of using Raman backscatter signals to infer temperature, a calibrated fiber Bragg grating (FBG) array is used to measure the temperature. Bragg gratings have previously been deployed as temperature measuring devices, usually as discrete devices individually spliced in a cable. The cable design presented in this study reduces deployment costs compared to discrete Bragg gratings, and can also scale up to 1000 gratings.

Additionally, an interrogation method has been developed for measuring the wavelengths of the FBG array. Traditional swept-wavelength interrogation techniques exist to measure FBG arrays, but they are typically limited to approximately 40 gratings. Like the cable, the interrogation method scales up to 1000 gratings at 1 meter grating spacing.

Numerous system performance tests were conducted in a laboratory setting and in a simulated well environment. A prototype cable was deployed in a test well alongside a standard DTS cable. The cables were exposed to temperature cycling by circulating hot and cold fluid. Measurements produced by the two cables were recorded and analyzed.

The prototype cable test results demonstrated that the grating cable is capable of higher resolution temperature measurement than conventional DTS. The prototype interrogator will be able to perform the measurement in less than 10 seconds, a fraction of the measurement time required by conventional DTS interrogation.

Results from other tests have demonstrated the ability to perform well with long lead-in distances without losing accuracy. With this increased range, the interrogator can be located away from the wellhead and in offshore wells, above water.
Predicting Middle Bakken Well Performance with Shale Capacity
Authors: Newgord C. , Mediani M. , Ouenes A. , O'Conor P.
Published: September 2015

Using geologic models of porosity, brittleness, natural fracture density, total organic carbon, and saturation of oil, we develop the Shale Capacity for the Bakken reservoir. First, the 3D surface seismic data are frequency enhanced through a broadband spectral inversion. With the enhanced 3D seismic, we generate many seismic volumes of curvatures, spectral properties, post-stack acoustic impedance inversions, and pre-stack elastic inversions. A neural network is used to rank the different seismic volumes against the well log properties and then find the conditional relationships between the attributes to develop a geologic model that is predictive of the property variation away from the well control. These geologic models are combined to build the Shale Capacity model.

We quantify the Shale Capacity with the Relative Intercepted Shale Capacity (RISC) to relate the Shale Capacity to 90-day Initial Production (IP). RISC is the percentage of a wellbore's horizontal length that intercepts low to zero Shale Capacity. We determine RISC for six of the twelve horizontal wells and derive a relationship between RISC and 90-day IP. For the remaining six horizontal wells, we predict the 90-day IP using the derived correlation. Finally, we qualitatively compare the microseismic events with the Shale Capacity. Near the heel of the well where the Shale Capacity is low, the microseismic event density is lower. Similarly, where Shale Capacity is highest, the microseismic event density is higher.
Successive Substitution Augmented for Global Minimization of the Gibbs Free Energy
Authors: Eghbali Sara , Okuno Ryosuke
Published: September 2015

The conventional approach to multiphase flash is the sequential usage of stability and flash calculations. It is a series of local minimizations of the Gibbs free energy, in which a false solution is obtained from fugacity equations for a fixed number of phases and corrected in the subsequent stability analysis. The robustness and efficiency of multiphase flash have been important issues to be resolved for compositional reservoir simulation with complex phase behavior.

This paper presents a new algorithm to solve the correct set of equations for global minimization of the Gibbs free energy for isothermal, isobaric, multiphase flash. The Peng-Robinson equation of state with the van der Waals mixing rules is used for thermodynamic properties.

The number of equilibrium phases is part of the solution in the new algorithm, in contrast to the sequential stability/flash approach. Therefore, false solutions are not necessary for multiphase flash with the new algorithm. The advantage of the new algorithm in terms of robustness and efficiency is more pronounced for more complex phase behavior, in which multiple local minima of the Gibbs free energy are present. It is straightforward to implement the algorithm because of the simple formulation, which also allows for an arbitrary number of initial compositions.
Multi-Scale Evaluation of Nanoparticle-Stabilized CO2-in-Water Foams: From the Benchtop to the Field
Authors: Worthen Andrew , Taghavy Amir , Aroonsri Archawin , Kim Ijung , Johnston Keith , Huh Chun , Bryant Steven , DiCarlo David
Published: September 2015

Although EOR with CO2 is practiced domestically on large scale, the potential for advancement is enormous. The ongoing search for better solutions has motivated extensive research on alternatives to surfactant-stabilized CO2 foams for CO2 mobility control. The formation of CO2-in-water foams lowers the CO2 mobility, resulting in improvement in sweep efficiency in field tests. The crucial unmet challenge in employing CO2 foams is to maintain long-term stability of foam to achieve high sweep efficiency for the duration of the flooding process. Surfactant-stabilized foams are inherently unstable so that maintenance of the low mobility requires continuous regeneration of lamellae in the small pores of the rock. Nanoparticles can potentially be used to provide much higher foam stability and thus long-term mobility control for CO2 floods. They can act like a foaming surfactant without some of the surfactant drawbacks. Here we present a turnkey approach for using surface treated nanoparticles in reservoirs. This involves: tests for stability in brines, transportability through cores, foam generation in beadpacks and cores when co-injected with CO2, quantification of CO2 viscosity enhancement, and finally modeling of field-scale effects. In this paper, we will outline the key details of nanoparticle design for CO2 EOR.
A New Approach for Simultaneous Estimation of Relative Permeability and Capillary Pressure from Coreflood Experiments
Authors: Jahanbakhsh Amir , Sohrabi Mehran
Published: September 2015

Relative permeability (kr) and capillary pressure (Pc) are the most important flow functions in numerical simulation of multiphase flow in porous media. The values of kr and Pc are conventionally measured in separate experiments often with different methods. kr curves are usually measured by performing corefloods in the laboratory using two methods namely, ‘steady state’ and ‘unsteady state’ experiments. Pc is normally measured by mercury porosimetry, the porous plate method or by centrifuge method. The drawback of determining relative permeability and capillary pressure separately is that they may not be consistent with each other and the measured Pc does not correspond to the kr which is measured from dynamic flow system. Therefore, simultaneous determination of Pc and kr for a given system would be preferred. History matching techniques have been applied in the past to estimate relative permeability and capillary pressure simultaneously from unsteady state core flood experiments. In previous attempts, two independent functions were used to generate these two flow functions in the process of the history matching. To reduce the associated non-uniqueness problem of history matching, some in-situ measurements such as saturation and pressure profiles may be included in the history matching data but this information is rarely available.

The objective of this study is to honor a known relationship between the core relative permeability and the Pc curve and improve the optimization process and the accuracy of the estimated Pc and kr. Making the kr function dependent on the Pc in the history matching process will reduce the number of tuning parameters and is expected to reduce the uncertainty associated with the history matching process. A Purcell type model, which is based on the physics of fluid displacement, is used as the basis for linking the permeability (or relative permeability) to Pc.
Adsorption Enhanced Transport of Hydrocarbons in Organic Nanopores
Authors: Riewchotisakul Sansarng , Akkutlu I. Yucel
Published: September 2015

In this paper we present the results of steady state methane flow in carbon tubes under reservoir conditions using nonequilibrium molecular dynamics simulations, which show that the organic capillaries in resource shales contain a mobile adsorbed phase. This mobility leads to a significant shift up in the flow velocity profile of the fluid across the diameter of the tube. The contribution of the adsorbed phase to transport is significant in capillaries with size less than 20 nm. A new permeability model is proposed which considers these observations. We use the bundle of capillaries approach and estimate that the permeability correction for organic pores of Marcellus shale has more than 50 % increase. Further research is required to consider the transport of the other hydrocarbons and their mixtures.
Miscible CO2 Water-Alternating-Gas (CO2-WAG) Injection in a Tight Oil Formation
Authors: Han Longyu , Gu Yongan
Published: September 2015

In this paper, miscible CO2 water-alternating-gas (CO2-WAG) injection in the Bakken formation is experimentally studied and optimized. First, tight sandstone reservoir rock samples from the Bakken formation are characterized. Second, the saturation pressure, oil-swelling factor, CO2 solubility, CO2-saturated Bakken light crude oil density and viscosity are measured. Third, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) of the Bakken light crude oil and CO2 at the actual reservoir temperature. Last, a total of nine coreflood tests are conducted through respective waterflooding, continuous miscible CO2 flooding, and miscible CO2-WAG injection. In the miscible CO2-WAG injection, different WAG slug sizes of 0.125, 0.250, and 0.500 pore volume (PV) and different WAG slug ratios of 2:1, 1:1, and 1:2 are used to study their specific effects on the oil recovery factor (RF) in the Bakken formation. In addition, miscible CO2 gas-alternating-water (CO2-GAW) injection is also tested as an opposite fluid injection sequence of the miscible CO2-WAG injection. It is found that in general, CO2 enhanced oil recovery (CO2-EOR) method is capable of mobilizing the light crude oil in the Bakken tight core plugs under the miscible condition. The miscible CO2-WAG injection has the highest oil RF (78.8% in Test #3), in comparison with waterflooding (43.2% in Test #1), continuous miscible CO2 flooding (63.4% in Test #2), and miscible CO2-GAW injection (66.2% in Test #8). Furthermore, using a smaller WAG slug size of CO2-WAG injection leads to a higher oil RF. The optimum WAG slug ratio is approximately 1:1 for the Bakken tight oil formation. More than 60% of the light crude oil is produced in the first two cycles of the miscible CO2-WAG injection. The CO2 consumption in the optimum miscible CO2-WAG injection is much less than that in the continuous miscible CO2 flooding.
An Integrated Approach to Optimize Production in Marcellus Shale Gas Reservoirs
Authors: Yu Wei , Wu Kan , Sepehrnoori Kamy
Published: September 2015

With the development of shale gas reservoirs, various fracture propagation models have been developed to predict hydraulic fracture geometry by considering the stress shadow effects. Also, many researchers have been working on development of various production-simulation approaches to simulate production from the complex fracture geometries. The objective of this study is to combine the fracture propagation modeling and reservoir simulation to optimize production in shale gas reservoirs. First, we have developed a semi-analytical model to simulate shale gas production from the complex non-planar fracture geometry with varying fracture width and fracture permeability along fracture length. The important gas transport mechanisms including gas slippage, gas diffusion, and gas desorption are considered. Second, we integrate the semi-analytical model with a three-dimensional fracture propagation model, which fully couples elastic deformation of the rock and fluid flow to simulate complex hydraulic fracture propagation, to optimize fracture treatment design in Marcellus shale gas reservoirs.

Specifically, the fracture propagation model is utilized to predict the more-realistic non-planar fracture geometry with varying fracture width and fracture permeability along fracture length. In this study, the effect of varying number of perforation clusters within a given stage ranging from 2 to 5 on the fracture propagation was investigated. Three values of stage spacing were considered including 100 ft, 200 ft, and 300 ft. After predicting the non-planar fracture geometry, the semi-analytical model is employed to simulate production from such fracture geometries. According to the well productivity, the optimal number of clusters per stage for varying stage spacing is discussed and determined. In addition, we compared the well performance with the optimal number of perforation clusters for the stage spacing of 100 ft, 200 ft, and 300 ft under a given horizontal well length of 2,500 ft. Furthermore, we used the integrated approach to analyze a well performance from Marcellus shale gas reservoirs. Through the field case study, the more-realistic non-planar fracture geometry was quantified. Also, the difference between the non-planar fracture geometry and ideal planar fracture geometry with equal fracture width and fracture half-length was compared. Finally, the optimal fracture treatment design for the field well development was recommended. This work can provide new insights into optimization of number of perforation clusters per stage within a given fracture stage and a better understanding of the non-planar fracture geometry in shale gas reservoirs.
Phase Envelope Calculations for Reservoir Fluids in the Presence of Capillary Pressure
Authors: Sandoval Diego , Yan Wei , Michelsen Michael L. , Stenby Erling H.
Published: September 2015

Reservoir fluids are multicomponent mixtures in confined spaces, where the role of capillary force becomes important when the average pore size is on the order of tens of nanometers, such as in tight rocks and shale. We present an algorithm for calculating the phase envelope of multicomponent mixtures in the presence of capillary pressure. The algorithm uses a rigorous equation of state (EoS) model, such as the Soave-Redlich-Kwong EoS, for phase equilibrium, and the Young-Lapace equation for the capillary pressure. The interfacial tension is calculated using a parachor based model. A full Newton method is employed to solve the governing equations of the vapor-liquid equilibria coupled with the capillary pressure equation. For a stable and automatic construction of the phase envelope sensitivity analysis is used in each step. The developed algorithm can reliably generate not just the bubble and dew point curves but also other quality lines with vapor fractions between 0 and 1. The algorithm has been used to calculate the phase envelopes of binary, multicomponent and reservoir fluid systems for pore radius from 10 to 50 nm. The presence of capillary pressure changes the saturation pressures in the whole phase envelope except at the critical point. The bubble point curve shows a negative change while the dew point curve shows positive and negative changes in the upper dew point branch and the lower dew point branch, respectively. In particular, the cricondentherm is also shifted towards a higher temperature. The change in the phase envelope becomes larger as the pore size decreases. The effects of composition and gas oil ratios are also discussed.
New Methods for Interpretation of NMR Measurements Acquired in Spatially Heterogeneous Rocks
Authors: Medellin David , Ravi Vivek R , Torres-Verdín Carlos
Published: September 2015

The interpretation of the Nuclear Magnetic Resonance (NMR) T2 distribution as a pore size distribution assumes homogeneous surface relaxivity, single-phase fluid saturation, and the absence of diffusion of spins across pores. Although these assumptions are true for homogeneous formations with single-phase fluid saturation, they do not hold for heterogeneous formations such as deep-water carbonates, where laminations, vugs, and a mixed solid composition result in non-uniform values of surface relaxivity and diffusion of spins across pores. These spatial heterogeneities in rock formations render the interpretation of NMR logs challenging and non-conclusive. Furthermore, methods to estimate permeability, such as the Timur-Coates and the Schlumberger-Doll-Research (SDR) method assume a single relaxivity value and, thus, cannot be applied to NMR T2 data from formations with non-uniform relaxivity values.

NMR mixing laws describe how to combine data acquired from homogeneous components, thus enabling us to predict the data resulting from a mixture of those homogeneous components. This paper develops a new method to interpret NMR distributions originating from highly heterogeneous formations using mixing laws for T2, T1 — T2, and T2 — D NMR data. This new method allows us to extract the magnetization decay of each homogeneous component from the total magnetization decay of the heterogeneous formation. Decomposing the magnetization decay allows us to estimate the T2 distributions for each individual rock component and use them to obtain improved estimations of petrophysical quantities of interest such as porosity, pore size distribution, and the intrinsic permeability of each homogeneous component.

We show how to use the linear mixing laws in laminated formations to extract the T2 distributions from each individual component of a heterogeneous rock and how to obtain an improved estimation of the permeability of the formation.
Bayesian Style History Matching: Another Way to Under-Estimate Forecast Uncertainty?
Authors: Vink Jeroen C. , Gao Guohua , Chen Chaohui
Published: September 2015

Current theoretical formulations of assisted history matching (AHM) problems within the Bayesian framework, e.g., ensemble Kalman filter (EnKF) and randomized maximum likelihood (RML), are typically based on the assumption that simulation models can accurately reproduce field data within the measurement error. However, this assumption does not hold for AHM problems of real assets. This paper critically investigates the impact of using realistic, inaccurate simulation models. In particular it demonstrates the risk of underestimating uncertainty, when conditioning real-life models to large numbers of field data. Even though it is well-known, that model error and under-modeling impacts Bayesian methods, the practical effect that uncertainty may be severely underestimated, simply by using all available data is not well appreciated. Besides highlighting this effect, also a mitigation strategy to counteract this problem will be proposed and shown to be effective for the analytical toy model as well as for the real field case used as tests in this paper.

After briefly reviewing the Bayesian method and its underlying assumptions, limitations of AHM approaches within the Bayesian framework are analyzed using a simple analytical model in which forecast uncertainty can be computed both with and without constraints due to historic data. In particular the model can be used to illustrate the impact of using an inaccurate, or incomplete, simulation model. The observations from this analytical work can then be generalized to real-life workflows that are currently implemented in many commercial and proprietary tools. To mitigate the observed problem, a fairly simple but effective modification of the AHM workflow is proposed and tested on the analytical test case.

The same mitigation procedure is then also applied to improve uncertainty quantification of production forecasts using a real asset model. In order to see if the proposed workflow indeed leads to a more credible uncertainty assessment for forecast results, a specific realization of the asset model is used to generate synthetic production data. The model used for history matching and uncertainty quantification uses a different geological realization and hence can never reproduce the production results (which are assumed to have negligible noise). Also in this realistic setting, it is shown that forecasts easily can be under-estimated when large numbers of data are used to constrain forecast uncertainty in an imperfect model with accurate data. This undesired effect comes out as the flip-side of the attractive property of Bayesian methods that model parameters can be inferred with increased accuracy if the number of data is increased in a perfect model with noisy data.
Three-Phase Relative Permeability in Consolidated Media
Authors: Kianinejad Amir , Chen Xiongyu , DiCarlo David A.
Published: September 2015

Relative permeability of oil in water-wet rocks in three-phase systems depends on water saturation in addition to oil saturation. This dependency results in infinite possibilities of combinations of phase saturations in three-phase space, making measurements of three-phase relative permeability difficult and time consuming. Therefore, measurements of changes in three-phase relative permeability in three-phase space are scarce. On the other hand, the existing three-phase relative permeability models for predicting these changes (e. g. hysteresis) are usually complicated and require several parameters. In this work, we measure three-phase oil relative permeability curves along different saturation paths by developing a gravity drainage technique that works in consolidated sandstone. The experiments consist of measuring in-situ saturations along a 2-ft long vertical Berea sandstone core at different times using computed tomography (CT) technique during gravity drainage experiments, along three saturation paths over three-phase space. We then obtain three-phase oil relative permeability directly from the transient in-situ saturations measured during each experiment. Our data show that at the same oil saturation, the three- phase oil relative permeability varies significantly depending on the saturation path in three-phase space. From these measurements we use standard and simple Corey relative permeability model to fit the results. We find that each saturation path exhibits a different residual oil saturation, and that the Corey model matches the data well once the residual oil saturation is given correctly for each saturation path, while keeping all the other parameters constant. Our results suggest that, contrary to previous results, three-phase oil relative permeability in water-wet media is only a function of oil saturation, if the residual oil saturation changes are accounted for accordingly. In other words, we conclude that the key to correctly model three-phase relative permeability is the use of correct residual saturations for each saturation path (history).
Chemical EOR for Offshore Platforms Using a Novel Chemical Gradient Design
Authors: Trine Eric , Suniga Pearson , Fortenberry Robert
Published: September 2015

Developing robust, low cost surfactant-polymer (SP) solutions for use in offshore oilfields has historically proven difficult. The objective of this study was to develop and test a practical EOR process for injecting surfactant-polymer mixtures in seawater followed by a polymer drive in seawater – we call this approach the chemical gradient. The main target for this approach is offshore applications for platforms with space and facility limitations where alternative sources of injection brine are not available or very limited, making it difficult to use a conventional salinity gradient design. A proposed strategy for modeling the chemical gradient is also included in this work.

The conventional way to design a surfactant-polymer (SP) flood is to use a salinity gradient. This is the simplest, most efficient and most robust design approach. This means the surfactant-polymer slug is injected at its optimum salinity and then followed by a polymer drive at a lower salinity, usually about 70% of the slug salinity. This can be done by blending brines with different salinities, desalinating or softening an available injection brine and other means. However, sometimes none of these alternatives are practical using an existing offshore platform.

We designed a high-performance SP flood requiring only seawater as the injection brine. We added a very small amount of a hydrophilic surfactant to the polymer drive following the surfactant/polymer slug to create a chemical gradient equivalent to a salinity gradient to improve robostness. We tested the design in an outcrop coreflood experiment and observed excellent performance including high oil recovery and propagation of the chemicals in a sharp bank.
Assessing the Consistency of Measurements and Models for the Kinetics of In Situ Combustion
Authors: Cinar Murat , Kovscek Anthony R.
Published: September 2015

One method to access unconventional, heavy-oil and natural bitumen resources is to apply in situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat to reduce oil viscosity and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. The complex nature of petroleum as a multi-component mixture and the multi-step character of oxidation reactions complicates substantially the kinetic analysis of crude-oil oxidation. Isoconversional techniques provide model-free methods for estimating activation energy and naturally deconvolve multi-step reactions. The isoconversional fingerprint is, essentially, the profile of activation energy as a function of temperature (from low to high) of the sample. As such, isoconversional methods are also useful as a screening tool to categorize the burning characteristics of different oils. In the literature there are substantially different kinetic models for the representation of reactions during in situ combustion. Some models feature multistep reactions in series whereas other models combine series and parallel reaction steps. Interestingly, there is no study comparing these models with each other as well as consistent experimental data. In this study, the performance of different models proposed in the literature and a new model is tested using kinetic cell simulations and compared to new experimental data. As the basis of the comparison, the isoconversional fingerprints associated with the models existing in the literature are compared. Results indicate that most of the models proposed are unable to reproduce the typical isoconversional fingerprint measured for crude-oil combustion. This lack of agreement explains, in part, the poor predictability of reactive transport simulations of ISC. Importantly, this work illustrates a methodology for assessing the consistency of a kinetic model with experimental data and identifies physically consistent models.
Study of Kerogen Maturity using Fourier Transform Infrared Spectroscopy (FTIR) and Thermogravimetric Analysis (TGA)
Authors: Dang S. T. , Sondergeld C. H. , Rai C. S.
Published: September 2015

Maturity of kerogen in shale governs the productivity of a shale formation. Produced fluids are strongly dependent upon organic type (governed by depositional fossils and environment) and thermal history. Different maturity measurement methods (vitrinite reflectance, Rock Evaluation, biomarkers) have been studied, but failed to precisely determine maturity levacross all levels of maturity. Vitrinite reflectance (%Ro) measurement cannot be applied for marine shales and pre-Silurian shales, which do not include plant materials. Tmax (main maturity indicator from Rock Evaluation pyrolysis) measurement is questionable for mature and post-mature samples. Most of biomarkers become useless when maturity level reaches condensate window. In this study, we introduce using Fourier Transmission Infrared Spectroscopy (FTIR) and Thermogravimetric (TGA) for both qualitative and quantitative assessment on organic maturity in shale. Separation of organic matter or identification macerals is not required by either technique; they are quick and objective tests providing two IR-based maturity indices. The first index, CH2/CH3, (from FTIR alone) shows good sensitivity up to the end of the condensate window. CH2/CH3 index decreases with more mature samples. The following CH2/CH3 values are used to define the immature (>1.63 ± 0.22), oil window (1.63 ± 0.22 to 1.3 ± 0.25), wet gas window (1.3 ± 0.25 to 1.13±0.05), and dry gas window (<1.13± 0.05). Whereas, the second index, Tmethane, (from TGA and FTIR) can help to extend the maturity scale beyond the condensate window; this overcomes the main limitations of Rock Evaluation and biomarker analyses. The index increases with maturity. The result shows Tmethane yields a good correlation with vitrinite reflectance, Tmethane = 83.6%Ro + 497.5 (R2 = 0.89.)
A New Pseudosteady Triple-Porosity Model For Naturally Fractured Shale Gas Reservoir
Authors: Obembe Abiola D. , Hossain M. Enamul
Published: September 2015

In the past decade a plethora of research in academia and industry has focused on understanding the fundamental flow behavior of naturally fractured shale gas reservoirs (NFR). Naturally fractured reservoirs are mostly modelled using dual porosity models, in such models the reservoir volume is described by a low permeability shale matrix block surrounded by a fracture system. In which, the matrix and fracture system is each modeled as a separate homogeneous medium. However, existing dual porosity models cannot justify high production rates from existing shale gas reservoirs. Observations from fractured shale gas reservoirs reveal that there exist sets of orthogonal fractures (induced micro fractures), with different properties from the natural fractures which must be accounted for.

This study aims to modify the existing triple porosity model proposed for naturally fractured shale gas reservoirs under the assumption of a fully pseudo steady state flow regime between the three contiguous porous mediums. A new analytical solution for the wellbore pressure and rate transient under closed outer boundary conditions, without the assumption of sequential flow between the three contiguous media has been successfully developed. To conclude this study, a thorough sensitivity analysis of some the dimensionless parameters related to the newly derived model on the rate transient behavior would be studied. This work would contribute to understanding of the physics of shale gas flow mechanism and help in better characterization of naturally fractured shale gas reservoirs.
Novel Analysis to Determine Gas Permeability
Authors: Salam Damian Dion
Published: September 2015

Permeability is one of the most fundamental properties of any reservoir rock required for modeling hydrocarbon production. However, it remains as an unsolved challenge to measure the gas effective permeability at different pressure while maintaining the same gas-liquid distribution and saturation in the core sample. This paper provides both experimental and analytical studies about measurements of gas permeability from conventional to tight gas reservoir. Measurements are conducted with fore-pressure and backpressure various from nearly 0 MPa up to 9 MPa. It is found that there is condition where the gas slippage effect can be reduced effectively so that gas permeability measurement can be improved significantly. Exerting a backpressure at the outlet of the core sample is the key to diminish the gas slippage effect. When the backpressure reaches a certain value, defined as the minimum backpressure, the gas slippage effect is eliminated so that the non-slip permeability can be obtained without using Klinkenberg Effect. When the backpressure exceeds the minimum backpressure, the measurement gives a constant value of non-slip gas permeability for a given core sample. Besides experimental studies, this phenomenon can be explained analytically by the concept of gas transport mechanism. In addition, pressure distribution profile based on the ratio of pressure at certain position to backpressure gives further comprehension. From this study, a method of gas permeability direct measurement is provided. The analysis indicates that the minimum backpressure increases with the decrease in permeability, which correlates uniquely for each reservoir type. Moreover, the gas effective/relative permeability can be determined directly in multiphase systems instead of measuring several apparent permeabilities at different pressures drop to obtain the Klikenberg permeability.