bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Study of Confinement Effect on Hydrocarbon Phase Behavior in Nano-Scale Porous Media Using Differential Scanning Calorimetry
Authors: Luo Sheng , Lutkenhaus Jodie L. , Nasrabadi Hadi
Published: September 2015

Phase behavior in shale remains a challenging problem in petroleum industry due to many complexities. One complexity arises from strong surface-fluid interactions in shale nano-scale pores. These interactions can lead to a heterogeneous distribution of molecules, which conventional bulk-phase thermodynamics fails to describe. Phase behavior in shale is altered from that characterized in PVT cells. The majority of current models are based on bulk-phase thermodynamics and efforts have been made using molecular simulation to gain insight into the nano-structure of confined fluids. However, to our best knowledge, the experimental data for hydrocarbon phase behavior in shale systems is severely absent.

In this work, we investigated the phase change in nano-scale capillaries using experiments. The controlled pore glasses (CPGs) were applied to model the nano-porous structure of shale reservoirs. CPGs (pore diameters 4.3 and 38.1 nm) infiltrated with hydrocarbons (octane, decane, and the binary mixture) are subject to differential scanning calorimetric (DSC) analysis. It's observed that the bubble point is affected by pore size dramatically: at 38.1 nm the confinement effect is insignificant, but at 4.3 nm two distinct bubble points appear with deviations as great as ±15 K relative to the bulk, suggesting two populations of evaporating fluid. Based on experiments and simulations, a two-state model for the nanoconfined hydrocarbons is proposed.

The bubble point is modeled using Peng-Robinson equation of state (PR-EOS) with the capillary pressure considered. The flash calculation is based on isofugacity and an interfacial tension model is accommodated. The modeling shows a general trend of increasing bubble point temperature with decreasing pore diameter, inconsistent with the experimental results. Besides, the “dual bubble points” behavior observed at 4.3 nm is not predicted by the model. This indicates the incapabilty of the bulk-phase thermodynamics in describing the behavior of nanoconfined fluids and the needs for molecule-scale simulation.
Unified Finite Difference Modeling of Transient Flow in Naturally Fractured Carbonate Karst Reservoirs - A 3D Case Study
Authors: He Jie , Killough John E. , Fadlelmula F. Mohamed M. , Fraim Michael
Published: September 2015

The modeling and numerical simulation of fluid flow in naturally fractured carbonate karst reservoirs are extremely challenging due to non-Darcy flow in vugs and caves connected by fracture networks. The momentum balance of such flow has been shown to be better described by the Brinkman equation both physically and mathematically, and many methods have been proposed in the literature dealing with the steady-state Brinkman model. We carry Brinkman's idea one step further and propose a transient flow model which consists of the Brinkman equation and a generalized material balance equation, and the latter has proven to be exact in the fractured carbonate karst reservoir. Finite differences are implemented for the solution of the proposed transient flow model. This solution method is more straightforward, easier to derive and implement, and more apt to generalization from 2D to 3D cases than alternative techniques.

Numerical simulation of the transient Brinkman model requires explicit solution of not only pressure at the center of each grid block, but also velocities at the interfaces between the blocks, which exaggerates the computational cost and makes the computational process more difficult and less stable. In this paper, we propose a simplified finite difference formulation of the transient Brinkman model, which significantly reduces the computational time of the simulation process, and improves accuracy and stability of the simulation results. We update our reservoir simulator with this new formulation and illustrate it with a complex 3D naturally fractured carbonate karst reservoir model. The results of this study form the foundation for future 3D multi-phase reservoir cases.
Map-Based Estimation of Reservoir Pressure and Saturation from 4D Seismic with a Data-Driven Procedure
Authors: Landa Jorge , Meadows Mark , Thacher Catherine , Waddle Robert , Williams Nneka
Published: September 2015

In this work we describe a mathematical procedure and associated data-driven workflow for map-based estimation of reservoir pressure and saturation changes using 4D seismic and well production/injection data. The practicality of the approach is illustrated with a field application from an offshore clastic reservoir under waterflood production. The application of the procedure results in maps of estimated reservoir pressure and saturation changes that can be used directly in field reservoir management and history matching of flow simulation models.

The outstanding feature of this data-driven approach is the reliance on field-observed data rather than on complex modeling and compute-intensive schemes typically found in classical mathematical inversion approaches. The focus is on joint use of acquired time-lapse (4D) seismic and measured well production/injection data.

Simple mathematical functions are used to model the correlation between 4D seismic and pressure-saturation information. The correlation models are calibrated with well data. Multiple seismic attributes are then used to infer map-based pressure-saturation change information.

Use of flow simulation, forward seismic modeling, and rock-physics models is limited to the feasibility analysis stage of the inversion process, where such information is needed to generate synthetic test data.

Uncertainty/probabilistic analysis in the map-based estimation of reservoir pressure and saturation changes is performed using the well-known Bayesian framework for inverse problems.

The paper adds a new case study to the relatively limited existing body of literature on data-driven methods for pressure-saturation inversion from 4D seismic, where very few such field examples have been published to date. The innovative component in this work consists of a novel application of a data-driven inversion approach that improves the usefulness of the technology in real-data environments.
A New Salinity-Independent Cased Hole Water Saturation Method Using Pulsed Neutron Oxygen Activation Logging: Physics, Modeling and Interpretation
Authors: Chace David , Inanc Feyzi , Zhang Qiong , Gade Sandeep
Published: September 2015

The carbon/oxygen (C/O) method of pulsed neutron logging has been widely used since the mid-1970s for saturation monitoring in cased hole wells. C/O logging measures the ratio of gamma rays created by inelastic neutron scattering by carbon and oxygen to determine formation water and oil saturation. A key benefit of C/O logging is that it provides a salinity-independent measurement. However, very slow logging speeds are required to achieve the necessary statistical accuracy. This paper introduces a faster salinity-independent water saturation method based on oxygen activation (OA) logging, including the physical principles, modeling and interpretation of laboratory test pit data.

Oxygen activation can be induced when fast neutrons with an energy greater than 10 MeV interact with isotope O-16, resulting in the creation of radioactive N-16 and subsequent generation of gamma rays with a predominant energy of 6.13 MeV. These detected activation gamma rays are directly indicative of the amount of oxygen in the vicinity of the neutron source. Modeling of the oxygen activation response accounts for formation lithology, porosity, borehole fluid, wellbore geometry and logging speed. Formation water saturation is determined by comparing the measured oxygen activation gamma rays to the modeled activation response envelope.

A custom-designed test pit was fabricated to evaluate OA water saturation feasibility. Comparison of C/O and OA measurements obtained over a range of logging speeds, and with different wellbore fluids, has confirmed that OA measurements can be successfully used to determine formation water saturation. In addition, the OA water saturation measurement is feasible at much faster logging speeds than C/O logging and can significantly reduce operation time. Indeed, the maximum practical logging speed in the test facility was 16 ft/min, and the upper speed limit of OA logging remains to be determined. This will best be evaluated through field testing in actual well conditions.

OA logging is a new alternative to C/O logging for through-casing salinity-independent water and oil saturation measurement. With the ability to log at much faster speeds, OA logging can provide significantly improved performance considering the operational limitations of C/O logging.

This paper presents the laboratory experiments, modeling and interpretation that confirm the viability of the OA water saturation measurement. In continuation of this work, the OA method is being applied to acquire and interpret field data from different wells globally. Various logging scenarios will be evaluated, including mixed lithology formations, flowing wells, and openhole completions. This will be presented in a separate publication.
Permeability Measurement of Organic-Rich Shale - Comparison of Various Unsteady-State Methods
Authors: Jin Guodong , Pérez Héctor Gonzàlez , Al Dhamen Ali Abdullah , Ali Syed Shujath , Nair Asok , Agrawal Gaurav , Khodja Mohamed R. , Hussaini Syed Rizwanullah , Jangda Zaid Zaffar , Ali Abdulwahab Zaki
Published: September 2015

Accurate determination of organic-rich shale permeability is still a major challenge. Various methods have been proposed to measure the permeability on core plugs or crushed samples under various stress conditions using different fluids. Permeability obtained from core plugs and their crushed samples could differ by two orders of magnitude, potentially painting very different views of the reservoirs and resulting in differences in asset development workflows. This situation only reinforces the need for considerable additional focused work to quantify tight rock permeability and better understand the measurement method dependence.

This paper presents the experimental comparison of three different unsteady-state transient methods for measuring the permeability of organic-rich shale plugs: pressure build-up, pulse-decay and oscillating pulse techniques. Permeability measurements are conducted isothermally using nitrogen gas on core plugs from the Barnett, Eagle Ford, Marcellus and Mancos formations at the same confining pressure and pore pressure. These plugs differ in mineralogy, total organic carbon (TOC), nuclear magnetic resonance (NMR) and helium porosity. Fractures are observed through the horizontal samples along the gas flow direction, while vertical samples do not have fractures. For each plug, the permeability tests begin with the pressure build-up measurement, and are followed sequentially by the pulse-decay and oscillating pulse methods whenever applicable. The plugs are then cut into smaller sizes for continuation of permeability tests and investigation of the permeability dependence on the plug size.

For the samples analyzed, the permeability measured from the pulse-decay method is essentially identical to that from the oscillating pulse method. Compared to these two methods, the pressure build­up test generally gives a relatively higher value when requiring an independent porosity measurement to compute the permeability, while it gives a relatively lower value when no porosity is needed. However, the permeability difference among these methods is generally small. This indicates that the pressure build-up test can be used to perform permeability measurement on large core plugs that cannot be tested using the pulse-decay or oscillating pulse methods. There is no trend observed on the permeability dependence on the plug sizes used. Depending on fracture distribution and connectivity, the measured permeability of horizontal samples is randomly affected by the sample sizes, indicating multiple samples with various sizes may be required to obtain a representative permeability value for horizontal plugs. Vertical plugs show little permeability dependence on the sample sizes. Consequently, a small vertical plug can be used for very tight rocks enabling quicker matrix permeability measurements.
Fracture Detection Using the Conductivity Triaxiality Index
Authors: Wang Gong Li , Abubakar Aria , Barber Tom , Alatrach Samer
Published: September 2015

Over the years, triaxial induction tools have found applications in not only determining formation resistivity, anisotropy, and dip, but also in detecting fractures. Fracture detection techniques provide useful information in identifying fractured reservoirs because fractures provide both space for hydrocarbon storage and also the channel for fluid flow. When fractures are developed in a formation, the formation can exhibit triaxially anisotropic conductivity if the fractures are filled with a fluid with a significantly different conductivity than that of the formation. This is particularly true for transversely isotropic formations. In an isotropic sedimentary formation, fractures can also cause the formation to be triaxially anisotropic if the geometric properties, orientation and porosity of fractures are varied from place to place in the fractured zone.

In this paper, we present a new method that uses the information of the conductivity tensor to detect fractures. The new method indicates the presence of contrasting fluid-filled fractures by the difference in three conductivity components of the tensor. This difference is called triaxiality in the paper. The conductivity tensor is found using an inversion approach. In addition to three conductivity components σx, σy, and σz, the inversion also provides three Euler angles γ, α, and β. Multiple initials for Euler angles are used to ensure that a global minimum is obtained. The inversion is followed by a rotation operation on the inverted conductivity tensor to eliminate the ambiguity effect of the principal coordinate system. The new Euler angles are found by solving a minimization problem.

We have applied the new method to both synthetic and field examples. Synthetic examples show that the rotation operation is indispensable to remove the ambiguity effect of the principal coordinate system. Furthermore, it is shown that the triaxiality is indeed responsive to the presence of fracture. Previous processing of the field example has showed that fractures exist in many zones. The triaxiality index derived from the new method is found in a fairly good agreement with the fracture index from a previous method.
Physics-Based Approach for Shale Gas Numerical Simulation: Quintuple Porosity and Gas Diffusion from Solid Kerogen
Authors: Lopez Bruno , Aguilera Roberto
Published: September 2015

The objective of this study is to provide a detailed physics-based explanation of production behavior of shales through the construction of a fully implicit finite difference numerical model that includes five storage mechanisms as well as the gas dissolved in solid kerogen. Shale gas reservoirs are characterized by multiple porosities such as inorganic matrix porosity, organic matrix porosity, microfracture and slot porosity, hydraulic fracture porosity created during the stimulation of the shale reservoir, and adsorbed porosity. In addition to this complex system, natural gas is trapped and stored in shales as free, adsorbed and dissolved gas.

Simulation of shale gas reservoirs is conducted by the introduction of a quintuple porosity approach in which the aforementioned storage mechanisms, the dominant nano-scale structure of shales and the presence of viscous flow, slip flow and Knudsen diffusion are honored in order to rigorously represent the physics associated with gas flow in these types of reservoirs.

Simulated results are presented as cross-plots of P/Z vs. Gp, which are used to show the effects of the quintuple storage formulation on the behavior of shale gas reservoirs. The gas contributions due to free gas, adsorbed gas and dissolved gas are highlighted as part of the numerical modeling results. The numerical model is also compared against real data from Devonian gas shales. The characteristic signature of actual data is reproduced by the numerical simulator developed in this work.

This paper presents a comprehensive methodology, which efficiently handles all the storage mechanisms present in shale gas reservoirs in such a way that better estimates of original gas in place (OGIP) and recoveries can be performed. This work also helps to reduce the uncertainty related to shale gas production forecasts since the current available simulators do not efficiently represent the physics of these unconventional reservoirs. Therefore, it is crucial to consider all the factors addressed in this paper. Ignoring one of these elements will lead to underestimation of gas production from shale gas reservoirs.

It is concluded that the simulation approach proposed in this study provides a more accurate reservoir model for shale gas representation and a better understanding of the flow mechanisms occurring in these reservoirs.
Effective Method for Monitoring Oil Based Mud Contamination in Wireline Formation Testers Sampling
Authors: Pineda W. , Gozalpour F. , Hagshenas Mehdi
Published: September 2015

The Wireline Formation Tester (WFT) is a well-developed technology to collect representative downhole fluid samples. Collecting low contamination downhole samples in wells drilled with miscible oil-based mud (OBM) is challenging because the process must balance the need to acquire a sample with the desired level of contamination while using the minimum rig time. In addition, quantifying the level of OBM contamination is subject to vendor's experience and their software.

We introduce a simple but effective method for monitoring WFT sampling when targeting the low levels of contamination needed for asphaltene onset pressure (AOP) analysis. Accurate AOP measurement is critical to mitigate flow assurance risks and AOP accuracy is affected by the sample contamination levels.

The intent of this method is not to replace the well-established clean out monitoring techniques but rather to complement them. This approach uses gas oil ratio GOR data from downhole fluid analyser to predict the maximum GOR that would be achieved by pumping at infinite time and use this value as a reference to determine when the clean out process should stop and filling the sample bottles should begin.

Traditional contamination prediction methods are mainly developed for single probes and face limitations when applied to sampling with concentric probes. Although the examples used are based in focused type probes, this approach is independent of probe geometry and vendor technology.

Success stories of applying the method for obtaining high quality samples in nine sampling stations from three reservoirs in the Gulf of Mexico are presented. Laboratory analysis showed the highest OBM contamination from the samples collected was less than four weight percentage of stock tank oil (STO). In five stations the contamination was equal to or less than 1%. The highest difference between the contamination predicted real time and contamination measured in the laboratory was 1.8%.
Treatment of Condensate and Water Blocks in Hydraulic Fractured Shale Gas-Condensate Reservoirs
Authors: Ganjdanesh Reza , Rezaveisi Mohsen , Pope Gary A. , Sepehrnoori Kamy
Published: September 2015

The accumulation of condensate in fractures is one of the challenges of producing gas from gas-condensate reservoirs. When the bottomhole pressure drops below the dew point, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gas production rate. This reduction of gas productivity is in addition to the reduction due to water blocking by the fracking water. Solvents can be used to remove liquid blocks and increase gas and condensate production rates. In this paper, dimethyl ether (DME) is introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flow back after the treatment. We compare its behavior with both methanol and ethanol solvents.
An Experimental Study of the Impact of Injection Water Composition on Oil Recovery from Carbonate Rocks
Authors: Alshakhs Mohammed J , Kovscek Anthony R
Published: September 2015

An experimental investigation is presented that shows oil recovery and wettability changes accompanying alteration of injection water salinity. The study aims to provide a better understanding of the impact of salinity leading to greater oil recovery and the mechanisms that take place for carbonate rocks.

A series of forced imbibition experiments was conducted using crude-oil at different total salinity and ionic composition. In the first test set, three brines of different salinity were injected sequentially into reservoir cores with realistic initial oil and water saturation. Additional incremental oil recovery of 4.4-6.4% of the original oil in place (OOIP) was observed, during the tertiary stage. The injection of synthetic seawater, that has a salinity of 55 kppm, was replaced by a new brine (MgSO4) of similar total salinity (45 kppm) and rich in Mg2+ and SO42- ions. Injection of twice-diluted seawater of 27 kppm, during the tertiary stage, yielded an incremental oil recovery of 0.9%. The effect of reducing the total salinity was evaluated in a second test set using outcrop limestone cores and another crude-oil. An incremental oil recovery increase of 6.5% was observed when twice-diluted seawater (29 kppm) was injected during the tertiary stage following seawater injection.

Wettability alteration was assessed using classic crude-oil contact-angle tests on smooth calcite surfaces. Contact-angle measurements suggest that the release of oil is caused by a wettability shift toward water wetness. The static water contact-angle was reduced in first test set from 92.7° to 55.4° when the brine was switched from seawater to the magnesium-rich brine. Similar reduction was observed in the second test set. The static water contact-angle was reduced from 70.1° to 58.9° when the brine was switched from seawater to twice-diluted seawater.

The contribution of the rock/brine/oil interactions to the wettability was evaluated by measuring zeta potential of water/oil and water/solid interfaces. DLVO (Derjaguin, Landau, Verwey and Overbeek) theory of surface forces, using the measured zeta potentials rationalized observations of oil recovery in the case of low water salinity.

The finding of this work provides a new approach for utilizing salinity alteration to achieve greater oil recovery. The impact of water salinity is usually correlated with low water salinity or with increasing the concentration of the key divalent ions. This study combines both salinity modification schemes to increase tertiary oil recovery.
Capillary Corrections to Buckley-Leverett Flow
Authors: Deng Lichi , King Michael J.
Published: September 2015

At the reservoir scale, multiphase fluid flow is well characterized by the Buckley-Leverett flow equations, neglecting capillarity. However, as we extend our studies in higher resolution using multiscale calculations, or evaluate tighter or higher contrast heterogeneous or fractured reservoirs, capillarity becomes increasingly important. To improve the understanding of these situations, we have extended the analytic solution of the Buckley-Leverett equations to include capillarity. Specifically we have solved the incompressible waterflood flow equations along a streamtube or streamline with arbitrary cross-section for a heterogeneous porous media with variable injection water rate, including capillarity. The methodology is an application of a singular perturbation expansion with matched asymptotic solutions. The outer solution is identical to the continuous portion of the Buckley-Leverett saturation profile while the inner solution is the steady state solution first noted by Terwilliger experimentally. The two solutions match at the Buckley-Leverett shock saturation and all solutions can be expressed in closed form. The result of this analytical solution is tested against high resolution flow simulation to verify its validity. This analysis is also applied to the calculation of capillary end effects in laboratory core floods, where the length scale of the saturation correction can be predicted. We also demonstrate, as the shape of the saturation profile near the front depends upon the capillary pressure function, that this analytical solution can used to interpret experimental data and derive and calibrate the capillary pressure function.
Advances in Flowback Chemical Analysis of Gas Shales
Authors: Zolfaghari Ashkan , Tang Yingzhe , Holyk Jordan , Binazadeh Mojtaba , Dehghanpour Hassan , Bearinger Doug
Published: September 2015

Recently, flowback chemical analysis has been considered as a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging due to the complexity of shale-water interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water.

The water samples at different flowback times and the shale samples are collected from three wells completed in the Muskwa, Otter-Park, and Evie members of the Horn River Basin. The water samples consist of aqueous solution and precipitated salts. The water samples are digested in nitric acid to dissolve the precipitated salts, and are analyzed at both intact and acid-digested conditions using ICP-MS. The flowback salts are weighted and analyzed using XRD and SEM-EDXS. A sequential ion-extraction is performed on the shale samples; and the extracted ions are categorized into three tiers of loosely-, moderately-, and strongly-attached ions.

The concentration of monovalent cations in both intact and acid-digested samples is higher than that of divalent cations. Also, the concentration of all cations is higher in the acid-digested samples compared with that in the intact samples. The ratio of divalent cations concentration in the acid-digested samples to that in the intact samples is higher than that for the monovalent cations. This ratio increases for the divalent cations over time, while it remains constant for the monovalent cations. Additionally, for the acid-digested samples the monovalent cations concentration has an initial sharp increase followed by a slower increase at later flowback stages; while the divalent cations concentration increases continuously over time. These results suggest that the majority of the ions in the early flowback water are loosely-attached monovalent ions. These ions can be originated from the mixing with in-situ formation brine, dissolution of soluble precipitated salts, or leaching of exchangeable cations from the clay minerals. Similarly, the role of relatively slow water-rock interactions (such as leaching of divalent exchangeable cations, e.g. Ca2+,) increases at the later flowback stages. XRD and SEM-EDXS analyzes of the flowback salts indicate that sodium chloride, potassium chloride, and calcium carbonate are the major salts. The sequential ion-extraction reveals that the majority of the monovalent cations are in the loosely-attached tier. However, majority of the divalent cations are moderately- /strongly-attached to the rock. The strongly-attached portion of the ions is determined by acid digestion of the rock sample at the final stage of sequential extraction process. These strongly-attached ions cannot be easily released by hydraulic fracturing and therefore, has small effect on the flowback water chemistry.
Pore Size Distribution from Water Adsorption Isotherm
Authors: Zolfaghari Ashkan , Dehghanpour Hassan
Published: September 2015

Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we develope a model to characterize PSD of shales using water adsorption isotherms. We apply the model on several shale samples and compare the results with the PSDs obtained from BET (Brunauer-Emmett-Teller) analysis using the N2 and CO2 adsorption isotherms.

The proposed model describes the relationship between the cumulative adsorbed water and the size of the invaded pores due to capillary condensation during the water adsorption process. A set-up is designed to obtain water adsorption isotherms. The shale samples are placed in a sealed environment with a controlled relative humidity (RH). Different saturated salt solutions are used to control RH. At the end of the adsorption process, the model is applied to calculate PSD of the shale samples using their water adsorption isotherm. In order to evaluate the model results, we used BET analysis to obtain PSD from the N2 and CO2 adsorption isotherms. Moreover, the specific surface area (SSA), pore volume (PV) and the average pore size of the shale samples are also obtained from the BET analysis to compare the proposed model and BET results. The results of both BET and the proposed model indicate that the majority of the pores are smaller than 10 nm. However, the model results from the water adsorption show a bimodal PSD, while the BET analysis shows a unimodal PSD. Also, the model calculates small pores of less than 1 nm, while BET does not detect these pores. Water adsorption by clay minerals at low RH values is a possible reason for this discrepancy. Furthermore, the sample with higher clay content shows larger hysteresis at the end of the sorption (adsorption-desorption) experiment; suggesting that the clay-bound water cannot be easily removed during the desorption process.
Advancing Multidisciplinary Training and Development for Young Professionals in the Oil and Gas Industry
Authors: Holderby Eric , Van Domelen Mark
Published: September 2015

Within the ever increasing collaborative environment of the oil and gas industry, there has been significant growth in the need for professionals to be able to operate across industry-standard definitions of disciplines. Influences, such as economic cycles, growth in other industries, and population growth have created a growing demand for young professionals to assume responsibilities and management duties at a rapid pace. While educational advances within the university setting are making efforts to close the gap necessary to supplement this demand, the majority of the responsibility to develop competent employees lies with the employer.

Employers within the industry are beginning to realize and act on the need for structured training and development programs to help ensure employees are adequately prepared and familiar with multiple concepts of business, even across historically set up discipline divisions. This is particularly true within technical disciplines, because there is a great demand for these technical employees to fulfill roles and responsibilities that push them beyond their technical training and typical roles. Moreover, the rapid increase in the use of technology necessary to operate in the unconventional reservoir setting has created a situation of dependency on these technical employees to take on managerial and strategic business-focused roles.

Historically, technical employees within the oil and gas industry have operated within specific niches according to their education and/or experience. However, an increase in multidisciplinary project management as it relates to asset development suggests the need for technical employees to develop themselves across discipline boundaries. Training and development programs that cover all aspects, from geology and geophysics, drilling, completions, production, and asset management, are essential to prepare these young professionals for the responsibilities within this setting. In addition to broader technical training, soft skills training to adequately prepare technical employees to express difficult concepts coherently and effectively is paramount to bridging the gap between the technical and nontechnical portions of the industry.

This paper outlines suggested advances that can be made to effectively train and develop technical employees in this evolving setting during entry level training and more specifically mid-career professional development. A description of historical training methods in the industry, current trends of training technical employees within a certain discipline, and the developing understanding of the importance of multidisciplinary technical collaboration are also discussed.
Nature friendly Application of Ionic Liquids for Dissolution Enhancement of Heavy Crude Oil
Authors: Sakthivel Sivabalan , Velusamy Sugirtha , Gardas Ramesh L. , Sangwai Jitendra S.
Published: September 2015

The upstream petroleum industry faces operational and technical challenges due to the production of crude oil containing waxes, asphaltenes and aromatic compounds and also due to the formation of gas hydrates resulting in their deposition in the surface and production equipments and in offshore pipelines affecting the safer operations, in turn resulting in huge production losses, and threatening the environment. It is also estimated that, all over the globe there are more than double the times of reserves of heavy and extra-heavy crude oil than the lighter one. In spite of this, the production of heavy oil is still low. As the world’s demand for light crude oil continues to increase tremendously, the supplies of these easily extractable crude oil continues to decrease although efforts have already been made to extract the heavy and extra-heavy oil that was previously considered uneconomical to produce and process. The enhancement in the solubility of heavy crude oil in solvent and ionic liquids mixture is investigated using UV-visible, FT-IR and 13C- NMR spectroscopic techniques. Ionic liquids also aid in the reduction of surface forces between oil-water systems thereby helping for the recovery of entrapped oil from exhausted reservoirs which have failed to produce the residual oil. This work also investigates the role of ionic liquids in reducing the surface forces at the interface of crude oil-water system. Synergistic effect of ionic liquids along with brine has also been tested. It is observed that, the dissolution of heavy crude oil is more in the solution with ionic liquid than with the solvent alone. Solubility of heavy crude oil in the presence of studied ionic liquids and in the studied solvents increases about 60 %, when compared with the solutions of heavy crude oil in solvents without ionic liquids. Measured interfacial tension values between solutions of ionic liquid and crude oil reveal that these ionic liquids are successful in reducing the surface tension and interfacial tension. Improved efficiency in reducing the interfacial tension using salt and ionic liquid mixture has been observed between crude oil and the aqueous solution of ionic liquid. This method also helps in minimizing the amount of organic solvents that may be used to a considerable extent. Delayed production of crude oil due to flow- assurance issues or the loss of valuable fuel which remains unrecoverable due to the huge and cumbersome technical difficulties in the prevailing enhanced oil recovery processes could be greatly reduced by employing the use of ionic liquids.
Petrophysical Evaluation and 3D Geostatistical Reservoir Modeling of Okati Field for Development, Shallow Offshore, Niger Delta
Authors: Alabrah Bibobra Michael
Published: September 2015

In order to ensure optimal hydrocarbon recovery and sustained production, it is imperative to carry out reservoir characterization and modeling, that is aimed at facilitating a holistic field evaluation geared towards effective development strategies and optimal field performance.

Okati field located on the continental shelf in water depths of 210-250 feet in shallow Offshore, Eastern Niger Delta, was investigated to determine the petrophysical properties of the reservoirs, and model the 3D spatial distribution of the properties of H3 reservoir using geostatistical techniques. Well logs, core, and pressure data were analyzed and interpreted in order to assess the hydrocarbon potential of these reservoirs.

The structural 3D grid surface and models were generated with inputs of the interpreted petrophysical parameters using Petrel and Interactive Petrophysics. These parameters were upscaled to provide discrete facies and continuous properties. The reservoirs (H1, H2, H3, H4, H5 and H6) have good effective porosities that range from 12 to 27%, high net-to-gross values that range from 55 to 89%. It was deduced that, the field has very good hydrocarbons saturation (range from 55 to 88%). The porosity and permeability models built indicate that, wells 2 and 3 have better storage and flow capacities relative to well 1. The fluid contact and water saturation models however, show that, well 3 is close to the oil-water-contact and has high water saturation which makes it a poor candidate for completions to avoid early water breakthrough. The volumetric assessment indicates 38.4MMBO of STOOIP.

It is concluded that, apart from H1, all the other five reservoirs have good petrophysical properties, hence, from a petrophysical standpoint; they are prospective candidates for future completions and development.
Mathematical Modeling Of Two-Phase Production From Unconventional Wells Using Analogy To Nature
Authors: Mikolajczak Edyta
Published: September 2015

Determining the changes of production is the key aspect of forecasting the exploitation of unconventional reservoirs. Two-phase flow and flowback after fracturing is observed in that resources. To get to know production profile is needed to find the relationship between produced water and produced gas.

This paper presents a new mathematical model for two-phase production forecasting, based on the populations dynamics model. The idea of this work is to use system of two logistic equations with additional term for modeling water and gas production declines. This paper is a continuation of my previous work connected with mathematical modeling of single phase flow in unconventional reservoirs.

The production process of unconventional wells divides it into three stages: dewatering, stabilized flow, decline. During the initial phase of exploitation, water production initially exceeds that of methane, but as production continues, the volume of gas increases steadily while the amount of water decreases. Over the stable period the gas rate slowly peaks. After that water production remains low and gas declining tendency begins.

The proposed model uses the analogy of processes of competition occurring in nature to two-phase flow phenomena in gas reservoirs. The presented model has a widespread use in modeling the populations dynamics including competition between two species. It is a set of two differential equations, which describe both interspecies and intraspecies interactions.

This paper contains two main parts. Part one presents a brief reminder of my preceding work, while part two includes description and explanation of my new model and modeling results.

The proposed model was successfully applied to extremely low permeability gas wells. The model can very accurately trend the declines behavior of these wells. The modeling results were verified by the real industrial data.
Gas Permeability Evolution with Soaking Time in Ultra Tight Shales
Authors: Chakraborty Nirjhor , Karpyn Zuleima T.
Published: September 2015

The single phase matrix permeability to gas in ultra-tight rocks such as shales, are typically in the order of around 1 – 500nD. When these rocks are exposed to liquid invasion during hydraulic fracturing operations, gas permeability can become significantly lower, due to the formation of liquid blocks at the fracture-matrix interface. Post fracturing shut-in time or “soaking time” is thought to alleviate this permeability damage by allowing for liquid blocks to spontaneously dissipate into the reservoir, driven by the strong capillary forces present in tight rocks. However, this redistribution of fluid also results in the formation of a larger invaded zone which may further damage gas permeability.

This paper presents a means of analyzing the change in permeability on shale cores with soaking time and subsequent production. Key observations from this work are that the introduction of even relatively small quantities of liquids into the rock matrix can lead to a significant reduction in average permeability. Soaking time further exacerbates the situation by allowing fluid to spontaneously propagate deeper into the matrix. Effects such as clay swelling lead to irreversible impairment of base matrix permeability, and a low threshold water saturation for gas to become immobile means that any spreading of fracturing fluid with soaking time could reverse benefits accrued from lowering the fluid saturation in liquid blocks.

The experimental work done in the current study is on Marcellus and Haynesville shale samples. The results obtained on soaking time experiments are compared with similar experiments on conventional and tight sands. This comparative analysis indicates that soaking time is beneficial to rocks with relatively higher permeability and low clay content whereas it is detrimental to ultra-tight lithologies such as shales. These lab scale trends can help contextualize observed field scale production characteristics based on reservoir lithology, base matrix permeability, and duration of soaking time, and thereby, provide operators a scientific foundation for the selection of an optimum post stimulation gestation time before beginning production.
Thermodynamics of Flat Thin Wetting Films with Applications to Low- Salinity Waterflooding
Authors: Myint Philip C. , Firoozabadi Abbas
Published: September 2015

In the past several years, a number of papers have attempted to explain the phenomenon of improved oil recovery due to low-salinity waterflooding from the perspective of the thin brine films that wet the surfaces of the pores. Because of the complicated, multiscale nature of low- salinity waterflooding (LSW), the studies on this topic have been largely limited to phenomenological observations and explanations. Improving our understanding of thin liquid film thermodynamics is an important step towards developing our knowledge of LSW and optimizing the effect of brine chemistry on oil recovery.

In this work, we analyze two fundamental thermodynamic problems relating to flat thin liquid films. One problem concerns the expression for the Gibbs energy of the films. Thin liquid films undergo film tension work. There are conflicting results in the literature over whether to include the film tension work in the Legendre transform that relates the Gibbs energy to the internal energy of the films. We show that for the purposes of finding the equilibrium state, the Legendre transform must include the film tension term so that the chemical potentials are equivalent to the partial molar Gibbs energy. The second problem we examine involves the augmented Young equation, which is a condition for mechanical equilibrium involving the contact angle at the boundary between a thin liquid film and the bulk liquid droplet from which the film is formed. Two different expressions for the augmented Young equation have appeared in the literature. We show that under certain assumptions, the two expressions can be made equivalent.

We then briefly discuss how fundamental thermodynamic relations of thin liquid films can help explain the wettability alteration observed in LSW studies. We conclude with a summary of our main results.
A Comprehensive Model for Simulation of Gas Transport in Shale Formation with Complex Hydraulic Fracture Geometry
Authors: Yu Wei
Published: September 2015

A comprehensive model for simulating gas transport in shale formation with complex fracture geometry is still lacking in the petroleum industry. First, the current models are challenging to efficiently handle the complex non-planar fractures with varying fracture width and fracture permeability along fracture length due to very complicated gridding issues, an expensive computational cost, and complexities in development of computational codes. Second, conventional gas mass balance equation needs to be revised to include all important gas transport mechanisms such as gas slippage, gas diffusion, and gas desorption. Hence, the goal of this study was to develop a new model to fill this gap.

We present an efficient semi-analytical model by dividing fractures into several fracture segments to represent the complex non-planar fracture geometry and present a revised mass balance equation to consider all the important gas transport mechanisms for shale gas reservoirs. We verified this model against a numerical reservoir simulator for planar fracture by considering the effects of gas desorption, non-Darcy flow, and geomechanics separately. Transient flow behavior between planar fractures and non-planar fractures with and without considering the natural fractures was compared. Furthermore, a well with actual production data from Marcellus shale was analyzed. First, we use a three-dimensional fracture propagation model to generate more-realistic non-planar fracture geometry. Then, we apply the fracture geometry into a semi-analytical model to evaluate well performance. Contributions of each mechanism to gas recovery are then examined. Based on history matching and production forecasting, the difference of cumulative gas production between the realistic non-planar fractures and ideal planar fractures is about 20% at 30 years of production. In addition, the contribution of flow mechanisms such as gas slippage, gas diffusion, and gas desorption to gas recovery at 30 years of production compared to that without considering them is about 13%, 17%, and 22%, respectively. Totally, the contribution of all the important mechanisms is about 52%. Hence, modeling of gas production from the realistic non-planar fractures as well as modeling the important gas transport mechanisms in shale gas reservoirs is significant.

This work, for the first time, combines a complex non-planar fracture geometry with varying fracture permeability and the important gas transport mechanisms to efficiently analyze field production data from Marcellus shale. The model can provide significant insights into understanding the impacts of gas slippage, gas diffusion, gas desorption, and non-planar fracture geometry on long-term gas recovery prediction.