bluuebunny/crossref_metadata_2025 huggingface dataset:
MPD Training Competencies: The Challenges of a Young Product Line
Authors: Haggins Ryan
Published: June 2014

Managed Pressure Drilling (MPD) continues to offer a solution to today's growing number of previously "undrillable" technically-challenging wells. With more operating companies looking to incorporate MPD into their well designs and programs, service companies are facing a severe shortage of experienced field personnel capable of meeting this demand. To remain successful, the industry must be able to recruit, train and drive new personnel to competency in a timely fashion, minimize costs, and maximize productivity for the product line.

Training challenges faced by a young product line like MPD include the recruitment of competent field personnel on the rigs; the creation of training and competencies programs geared towards specified job roles; the development of informed instructors and mentors; and the implementation of an effective training system.

In this paper we will suggest the next steps of having a complete development program that focuses on training through a combination of computer based training (CBT), classroom training, and simulation with a hand's on equipment component. Competency that has specific performance criteria the employees will have to meet before advancing to the next level and a mentoring program through on the job learning. These three foundations will re-enforce concepts, techniques, and applications of MPD and ensure the industry will have a trained and competent work force that will meet the growing demand of this young product line.
Modeling Analysis of Transient Pressure and Flow Behavior at Horizontal Wells with Multi-Stage Hydraulic Fractures in Shale Gas Reservoirs
Authors: Wang Cong , Wu Yu-Shu
Published: June 2014

Handling flow through fractured media is critical for transient pressure and flow analysis in shale gas reservoirs, because gas production from such low-permeability formations relies on fractures, from hydraulic fractures and fracture network to various-scaled natural fractures, to provide flow channels for gas flow into producing wells. This study presents a numerical investigation of pressure and flow transient analysis of gas production from a horizontal, multi-staged well in shale gas reservoirs. A specialized three-dimensional, two-phase simulator is developed and used for this purpose, which incorporates known nonlinear flow behavior in shale gas reservoirs. First we discuss a multi-domain, multi-continuum concept for handling multi-scaled heterogeneity and fractures, i.e., using hybrid modeling approaches to describe different types and scales of fractures from explicit modeling of hydraulic fractures and fracture network in simulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix. Then sensitivity studies of transient pressure responses and flow rates are presented with respect to hydraulic fractures geometry, stimulated reservoir volume (SRV), and natural fracture density. We will also compare the behaviors with two different interporosity flow assumptions, fully-transient and quasisteady state flow. Unlike conventional reservoirs, their difference cannot be ignored due to the extremely low shale matrix permeability and significant gas compressibility. Specifically, we will analyze a field example from Barnett shale to demonstrate the use of results and methodology of this study.
Unconventional Asset Development Work Flow in the Eagle Ford Shale
Authors: Cook David , Downing Kirsty , Bayer Sebastian , Watkins Hunter , Sun Chee Fore Vanon , Stansberry Marcus , Saksena Saurabh , Peck Doug
Published: June 2014

The Eagle Ford Shale is recognized as the largest oil and gas development in the world, based on capital investment (Wood Mackenzie 2012). Development typically consists of horizontal wells stimulated with multiple hydraulic fracture stages. Almost $30 billion will be spent developing the play in 2013, and optimizing the completion design and spacing of these wells can result in large rewards for the companies involved. This paper presents a pragmatic integrated workflow, used to optimize development and guide critical development decisions in the Black Hawk field, Eagle Ford Shale. Geoscientists, reservoir, and completion engineers worked collaboratively to identify the optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells. Wide uncertainty exists in many key reservoir and completion parameters. Using stochastic realizations from ranges of key properties, uncertainty was reduced using the history matching process. The resulting calibrated reservoir scenarios formed the basis of optimization studies for development drilling and down spacing. Completion design parameters, including fracture stage length, perforation clusters per stage and landing point for the lateral, were evaluated in hydraulic fracture models. The resulting fracture geometries were simulated and the optimum completion design, and well spacing determined for each area. The optimal development was shown to vary by region, due to changing reservoir, fluid and geomechanical properties. The use of multiple subsurface realizations, spanning an appropriate range of uncertainty, was critical to the success of this study. Economic analysis across a range of potential outcomes enabled robust development decisions to be made. As a result of this work, field trials to test proposed changes to the completion have been initiated, and development drilling plans updated to reflect the optimal well spacing for each lease.
Evaluating the Benefits of Zipper Fracs in Unconventional Reservoirs
Authors: Sierra Leopoldo , Mayerhofer Mike
Published: June 2014

In cemented and cased wells, perforation cluster spacing is optimized based on the type of reservoir fluid, permeability, fracture conductivity, proppant distribution, and associated stresses to place multiple fractures along horizontal wellbores. Specifically, in very low-permeability reservoirs, the requirement for smaller perforation or fracture spacing might not be possible because of the geomechanical interference between fractures. In this case, the commonly used zipper-frac technique can provide a means to create fractures in projects with closer spacing.

The benefits of zipper fracs can be maximized by generating proper fracture geometry and properly staggering the perforation/fracture system. This paper reviews and discusses numerical reservoir-modeling results of zipper fracturing that demonstrate the individual or combined effects of the perforation/fracture staggering, comparing these to the fracture length, fracture overlap, fracture conductivity, and/or proppant distribution effects of a conventional completion that does not use the staggered zipper-frac approach. The simulation results are assessed over a wide range of unconventional reservoir permeabilities for both gas and light oil.
Imbibition Characteristics of the Barnett Shale Formation
Authors: Morsy Samiha , Sheng J. J.
Published: June 2014

In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Outcrop samples from the Barnett shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 7%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Barnett samples in distilled water, 2 wt% KCl, low pH solutions (0.74- 1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 24% using distilled water and low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution). Clay swelling can contribute to the Barnett oil recovery improvement by creating along bedding cracks. Oil recoveries from the Barnett shale can be improved by 56% when used 2 wt% NaOH solution and 88% when used 3 wt% HCl when added to 2 wt% KCl simulation base fluid. High pH solutions did not improve oil recoveries from the Barnett samples when added to distilled water due to pore plugging resulted from the combination of clay swelling with mineral dissolution. Low pH solutions showed along bedding cracks similar to distilled water effect on the Barnett shale samples that helped recovery accelerations, while higher pH solutions showed sever samples damage with higher alkaline concentrations (2 wt% NaOH).
Development of a Stress Dependent Permeability Model in Tight Gas Reservoirs: A Case Study in Cooper Basin, Australia
Authors: Rezazadeh Mehrdad , Haghighi Manouchehr , Pokalai Kunakorn
Published: June 2014

Substantial amounts of gas are accumulated in tight sand reservoirs in Cooper basin, Australia. This basin has a complex geomechanical stress regime. It is believed that the orientation of the minimum horizontal stress is changing and also there is a stress dependent permeability in this basin. These characteristics have a major impact on the gas recovery from different fields in Cooper basin.

It is well known that permeability decreases in sandstone reservoirs when the net confining stress on the rock increases as the gas pressure in the reservoir decreases, so permeability is reduced by gas production. This permeability reduction is more pronounced in tight sand reservoirs due to shear dilation of micro-fractures. In order to model stress dependent permeability, a fully coupled finite element geomechanical reservoir simulations is needed. However, since a large number of data and high computational time is required for this kind of modeling, stress dependent permeability model is a short cut for reservoir simulation. This paper presents an alternative approach of partial coupling of geomechanics and reservoir simulation in which only a finite difference simulator is used with much less computational time and lower cost.

In order to prove stress dependent permeability and develop a model, first a three dimensional hydraulic fracture model is constructed based on wire-line logs and mini-frac tests, then the resulting fracture geometry and conductivity are used as input data for dynamic reservoir flow simulation. We found that the reservoir permeability is changing at different time periods during pressure and production history matching.

In this paper a stress-permeability relationship was developed by assuming a fully elastic fractured network of flow path to the wellbore in a hydraulically fractured well. Then, this model was tested by a partially coupled geomechanical simulation in Big Lake field in Cooper basin. The results show that our approach has better predictions than when the permeability is assumed to be constant. By this procedure not only the predictions are improved but also the computational time is reduced.
Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin
Authors: Cullick A. S. , Carrillo M. , Clayton C. , Ceyhan I.
Published: June 2014

Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.
Analysis of Gas Production From Hydraulically Fractured Wells In The Haynesville Shale Using Scaling Methods
Authors: Male Frank , Islam Akand W. , Patzek Tad W. , Ikonnikova Svetlana , Browning John , Marder Michael P.
Published: June 2014

The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one of the deepest, with wells reaching more than 10,000 feet below ground. This uncommon depth and overpressure leads to initial reservoir pressures of up to 12,000 psi. These pressures are uniquely high among shale gas reservoirs, and require special treatment. We show that the methods developed by Patzek, et al., PNAS, 110, 19731-19736, can scale all individual wells' gas productions to fit upon a single, universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the type curves to take this into account. Furthermore, we introduce a PVT solver in order to calculate gas properties at up to reservoir pressures. When we apply the scaling theory to 2,199 individual well productions in the Haynesville, we find 1,580 wells which have entered exponential decline due to pressure interference. We use a simple physical model to determine the time to interference for wells with geologic parameters typical of the Haynesville, and use this to determine a field-wide permeability from the wells where we have observed pressure interference. From this, we arrive at time to interference for the remainder of Haynesville wells, and use this to arrive at production forecasts for all individual wells.
Development and Field Applications of Highly Conductive Proppant-free Channel Fracturing Method
Authors: Inyang U. A. , Nguyen P. D. , Cortez J.
Published: June 2014

Various methods are used to overcome choking effects in propped fractures to enhance and maintain well productivity (particularly in low-permeability reservoirs). Choking effects can result from permeability damage caused by fracturing gel residues, low-proppant concentrations, proppant crushing from high closure stresses or use of low-quality fracturing sand, or embedment/intrusion of formation materials into the proppant pack. This paper describes the development and field applications of a new well stimulation method for generating stable and highly conductive channels within a propped fracture to help maximize the transport capability of hydrocarbons from the formation reservoir to the wellbore.

Extensive laboratory experiments and large-scale testing were performed to evaluate the formation and stability of proppant aggregates and proppant-free channels (PFCs). Proppant-laden slurry (prepared by mixing fracturing sand coated with an agglomerating agent in a gel fluid) and crosslinkable proppant-free spacer fluid were pulsed intermittently to form proppant aggregated masses surrounded by proppant-free gel slugs. Highly conductive channels were formed surrounding the proppant aggregates after crosslinked gel slugs were broken and removed from the propped fracture, leaving behind proppant aggregated masses that supported the closed fracture.

Field trials were performed in unconventional and conventional oil formations. Injection pressures of proppant-laden slurry and proppant-free spacer using the pulsing approach were found to be significantly lower than those applied with conventional hydraulic fracturing treatments, indicating this new method helps alleviate the risks of screenout, as the proppant-free spacer sweeps and mitigates the proppant buildup in the near-wellbore (NWB) area. Field results showed production in wells treated with the proppant-free channel fracturing method increased significantly, even using 40% less total proppant, compared to production of offset wells in which conventional fracturing treatments were performed.
Regional Impacts of Lithologic Cyclicity and Reservoir and Fluid Properties on Eagle Ford Shale Well Performance
Authors: Tian Y. , Ayers W. B. , McCain W. D.
Published: June 2014

Since 2008, the Eagle Ford Shale has been one of the most active U.S. oil and gas plays. Regional variations of the frequency (cyclicity) and thickness of organic-rich marl and limestone interbeds influence well completion design, and these variations may be related to well production performance. To better understand the impacts of lithologic cyclicity and reservoir and fluid properties on well performance, we conducted an integrated, regional study using well logs, production data, and PVT reports.

Regionally, the Eagle Ford Shale is composed of 3 units. The Lower Eagle Ford consists of cyclic, interbedded organic-rich marl and limestone. To analyze lithologic cyclicity of the Lower Eagle Ford Shale in South Texas, We evaluated gamma ray logs from more than 500 vertical wells. A Matlab script was developed to count the numbers of organic-rich marl and limestone interbeds. Average bed thickness was calculated at each well and was mapped regionally. The numbers of both limestone and organic-rich marl interbeds increase from less than 2 in the northwest to more than 20 on the southeast. Lithologic cyclicity is greatest in La Salle and Karnes Counties, which are the most productive gas and oil regions, respectively.

Eagle Ford Shale reservoir and fluid properties from PVT reports were mapped to further evaluate regional variations of fluid types and well performance. Reservoir pressure, pressure gradient, oil gravity, and gas specific gravity were mapped. Reservoir pressure and pressure gradient are greatest on the northeast. Oil gravity and gas specific gravity maps suggest increasing thermal maturity from northwest to southeast, with increasing depth.

Well production rates are strongly influenced by lithologic cyclicity, pressure, and fluid properties. Understanding these relations in the lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results of this study provide a better understanding of Eagle Ford Shale reservoir characteristic and well performance, and the study approach may be used to assess productivity of other shale plays.
Practical Compartmental Model for Shale-gas Production by Multiple-Fractured Horizontal Wells Considering Transport Influenced by Nano-pore Proximity
Authors: Milad Benmadi , Civan Faruk , Devegowda Deepak , Sigal Richard F.
Published: June 2014

A practical simulation model is developed and demonstrated with applications for accurate characterization of production rate and pressure behavior with time in shale-gas reservoirs featuring horizontal wells intersected with multi-stages of hydraulic fractures. The model determines the contribution of each fracture stage to the overall production and predicts the pressure changes occurring in the fracture and matrix zones by a compartmental simulation approach. Various flow regimes of drawdown test are investigated for fracture diagnosis with different fracture permeability values to determine the external boundary effect. Our practical mathematical modeling, coupling the wellbore and reservoir hydraulics, is solved numerically by an iterative method to determine the flow rates coming into the horizontal well from multiple hydraulic fractures like the commingled layers intersected by a vertical well. This approach provides a reasonable description of behavior of multiple stages in shale gas reservoirs by considering the alteration of the gas transport properties and the changing apparent permeability under the effect of pore proximity of shale. Various applications of our non-Darcy simulation model demonstrate the importance of the corrections relevant for shale-gas reservoirs compared with the conventional Darcy flow without consideration of such corrections. Commensurate with field observations, when the non-Darcy flow corrections are considered, the cumulative gas production is higher compared with the conventional Darcy flow calculations which impact significantly on fracture and matrix pressure responses and production forecasting.
Fluid Compositional Prediction in Conventional and Unconventional Petroleum Systems
Authors: Horsfield B. , di Primio R.
Published: June 2014

In conventional petroleum systems, predicting gas-oil ratio and charge volumes ahead of drilling is a proven element of exploration strategy. In shale plays the liquid-gas cut-off must be known precisely, and production from the liquid-prone zone optimised. In-place does not necessarily correspond to produced GOR. In particular the transition from volatile oil, to condensate to wet gas is crucial, and production strategies must be developed accordingly. The first step in unravelling the fractionation phenomena occurring in both play types is to determine the bulk composition of the petroleum that is first-formed in the source rock. This is because all subsequent processes simply act upon and modify this original composition. Here we present numerous case studies where PhaseKinetics (di Primio and Horsfield, 2006), a compositional kinetic approach for predicting in-situ bulk fluid properties, has been employed in appraising acreage, and then go on to consider some of the critical aspects surrounding unconventional plays. In high pressure-high temperature (HPHT) reservoirs of the North Sea, which can be considered closed systems, black to light oil GOR distributions in the North Sea Viking Graben closely matched the predictions from our MSSV pyrolysis experiments (method of Horsfield et al., 1989) performed on the Draupne Formation source rock (di Primio and Skeie, 2004). In a similar study of the Jade and Judy Fields in the Central Graben (di Primio and Neumann, 2008), GOR predictions from MSSV pyrolysis bore a close resemblance to the natural HPHT system. Other examples of excellent GOR predictive capability are provided by modelling the Egret Shale and its generated petroleum in the Jeanne d'Arc Basin, Canada (Baur et al., 2012), and the Bakken Shale and its petroleums in the Williston Basin, USA (Kuhn et al., 2010, 2012). The lessons learned from conventional systems about petroleum compositional predictions can be readily applied to shale resource plays. Of key importance is the structure of the precursor organic matter, determined by organofacies and maturity. This applies both vertically and laterally. We also draw attention to the importance of determining whether cumulative or instantaneous fluids are found within the range of pore sizes present in shale. In the mid- to late oil window, instantaneous fluids from the Posidonia Shale are rich in gas and light liquids; phase envelopes change rapidly with increasing maturity. Cumulative fluids in juxtaposed strata have lower GORs. Fracking has to take these points into account or production GOR might turn out to be quite different to in-situ GOR, a phenomenon that has already been noted for the Eagle Ford.
Oil Shale In-Situ Upgrading by Steam Flowing in Vertical Hydraulic Fractures
Authors: Lee K. , Moridis G. J. , Ehlig-Economides C. A.
Published: June 2014

Oil shale, an organic-rich impermeable rock, is an abundant energy resource in the United States. Because few oil shale deposits occur in shallow formations, application of an in-situ process is necessary for thermal decomposition and subsequent oil and gas production. An earlier investigation indicated that cylindrical or planar in-situ electric heaters were more efficient than flowing steam through created fractures. This study investigates the efficiency of oil shale in-situ upgrading by steam flowing in vertical fractures. There are challenges in the through description of in-situ upgrading process because the kerogen decomposition involves of a series of complex and sensitive reactions, and results a large number of fluid and solid products. Expanding the Flow and Transport Simulator (FTSim) developed by Texas A&M University, we developed a fully implicit capability that describes the decomposition of kerogen in the oil shale and the resulting system changes with minimal simplification and assumptions. The decomposition process is represented by 6 kinetic reactions (resulting 10 components and 4 phases), involves coupled processes of mass transport and heat flow, and accurately accounts for phase equilibrium and phase transition thermodynamics. We applied our simulator to find a successful strategy for hydrocarbon production using steam that flows in vertical fractures created by multistage transverse fracturing in a horizontal (MTFH) well. The simulation of simultaneous heating and flowing provides the system change of oil shale reservoir during in-situ upgrading, and it indicates the necessary condition of successful hydrocarbon production from oil shale reservoir.
Difference in Behavior of the Waterflood Mechanism in Two Typical Areas of a Fractured Carbonate Reservoir, McElroy Field
Authors: Nguyen Hanh D. , Somerville James M.
Published: June 2014

The McElroy field is one of the oldest waterflood fields in the world producing from fractured carbonate reservoirs. The field has been producing since the 1920's and started waterflooding in the 1950's. It is obvious that the waterflood process plays an important role in improving oil recovery. However, due to the complex fractured carbonate reservoir setting, it is a big challenge for the waterflood management to attain the ultimate oil recovery. Geologically, the field is divided into four main areas. Each area behaves differently as a result of the waterflood process being influenced by the varying characteristics of the fractured reservoir. Understanding the waterflood mechanism's behavior in each area will help to develop an appropriate strategic waterflood plan. This study focuses on characterizing the differences between the waterflood performances in two areas of the field, the Low Permeability Area (LKA) and the Low Pressure Area (LPA).

The study used a database of about 680 wells within the LKA and LPA to define the contrasting waterflood performances in these areas. The main characteristics of the waterflood in the LKA and LPA to be discussed in this study consist of: –Oil production performance–Water production performance–Oil recovery performance–Waterflood management - the challenges and optimization opportunities

The main objective of the study is to define the similarities and distinctions of the waterflood mechanism performance of these two different fractured reservoir areas. This study also recommends further approaches to improve recovery efficiency in the McElroy field. The analysis can be used as a reference for waterflood design process in green or brown fields exhibiting similar conditions.
Mixtures of Anionic-Cationic Surfactants: A New Approach for Enhanced Oil Recovery in Low-Salinity, High-Temperature Sandstone Reservoir
Authors: Li Yingcheng , Zhang Weidong , Kong Bailing , Puerto Maura , Bao Xinning , Sha Ou , Shen Zhiqin , Yang Yiqing , Liu Yanhua , Gu Songyuan , Miller Clarence , Hirasaki George J.
Published: June 2014

Test results from mixtures of anionic-cationic surfactants significantly broaden the application scope for conventional chemical Enhanced Oil Recovery methods; these mixtures produced ultra low Critical Micelle Concentrations (CMC) as well as ultra-low interfacial tension (IFT) and high oil solubilization that promote high oil recovery.

Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications are described herein. Physical chemistry properties, such as surface tension, CMC, surface excess and area per molecule of individual surfactants and their mixtures were measured by Wilhelmy Plate Method. Morphologies of surfactant solutions, both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP), were studied by Cryo TEM. Phase behaviors were recorded by visual inspection including with crossed polarizers at different surfactant concentrations and different temperatures. Interfacial tensions between normal octane, crude oil and surfactant solution were measured by spinning drop tensiometer method. Properties of interfacial tension, viscosity and thermal stability of surfactant, surfactant-polymer, and alkaline-surfactant-polymer solutions, were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, polymer, SP and ASP. The core flooding experiments were conducted with water made of a simulated formation brine having approximately 5000 ppm TDS, and with a crude oil from a Sinopec reservoir.
A Novel Water Ionic Composition Optimization Technology for SmartWater Flooding Application in Carbonate Reservoirs
Authors: Yousef A. A. , Ayirala S. C.
Published: June 2014

Injection water with selective ionic content and composition is an essential requirement for SmartWater flooding application in carbonate reservoirs. SmartWater depleted in monovalent ions, but enriched in sulfates and divalent cations is desired for optimum incremental oil recovery in carbonates, which constitutes very complex water chemistry when compared to sandstones. Recognizing the utmost importance of water chemistry in the SmartWater flooding application, a novel water ionic composition optimization technology was investigated in this study. The proposed technology makes use of membrane desalination processes in a unique configuration to provide multiple water streams of widely varying ionic strength and content. Different water streams obtained from the novel solution can be effectively blended to yield SmartWater cocktail of desired ionic strength, composition and monovalent to divalent ion content optimally suited for carbonates.

SmartWater cocktails obtained from the proposed solution are also suited for application in other EOR processes such as polymer flood, surfactant flooding, dilute surfactant flooding, carbonated water flooding, miscible gas flooding and as boiler feed water in steam floods. Investigated scheme thereby offers a novel "one shop" solution to meet the complete suite of desired water chemistry requirements for different IOR/EOR processes. In addition, results of comparative evaluation between the investigated technology and other already known advanced desalination schemes highlight key advantages of the new solution in terms of better water ion tuning flexibility, higher recovery efficiency, lower energy requirement/foot-print and ease in operation.
Long Term Stability of Acrylamide Based Polymers during Chemically Assisted CO2 WAG EOR
Authors: Tovar Francisco D. , Barrufet Maria A. , Schechter David S.
Published: June 2014

CO2 flooding often results in poor sweep efficiency due to the high mobility ratio caused by its low viscosity. To mitigate this problem alternate injection of water and CO2 slugs, known as the water-alternating-gas process (WAG) is widely applied. Recently, numerical simulation and core flood experiments indicate that the use of chemicals in the water slug may improve mobility control during WAG, thus increasing the ultimate recovery and reducing the requirements for newly purchased or recycled CO2. Therefore, stability studies of common polymers used for EOR applications in CO2 saturated environments becomes necessary to address the technical and economic feasibility of this process.

In this paper, we report the results of two commonly used EOR polymers, a co-polymer of acrylamide and acrylate and a co-polymer of acrylamide and ATBS (2-acrylamido-terbutylsulfonic acid). To establish a base line for comparison, parallel experiments were conducted in two different oxygen free environments: one with CO2 and the other with nitrogen. Samples were hydrated and aged at reservoir temperature over 328 days. To isolate the effect of CO2 on the polymer, the water used for their hydration was stripped out of dissolved oxygen and the divalent cation concentration was decreased to reduce thermal and chemical degradation. Polymer samples were distributed in several bottles and removed at different times, and their apparent viscosity was measured as a function of shear rate and fitted to a power law model. The ability of the polymer solutions to retain their original apparent viscosity over time was used to quantify polymer degradation.

The results of this work show that CO2 impacts polymer stability, causing further degradation in both polymers tested when compared with the solutions aged with N2. The co-polymer of acrylamide and ATBS exhibited higher resistance to CO2 degradation as it was able increase its viscosity to 104 % of its initial apparent viscosity after 328 days, compared with the co-polymer of acrylamide and acrylate which only retained 54 % of its initial apparent viscosity after 215 days. Chemical degradation, hydrolysis and pH that affected the behavior of apparent viscosity over time also are addressed. We conclude that commercial polymers can be used during chemically assisted CO2 WAG when low divalent cation water is used at a reservoir temperature of 122 F.
Wettability, Trapping and Fracture-Matrix Interaction during WAG Injection in Fractured Carbonate Reservoirs
Authors: Agada Simeon , Geiger Sebastian
Published: June 2014

Relative permeabilities show significant dependence on the saturation path during enhanced oil recovery. This dependence (or hysteresis) is particularly important for water-alternating-gas (WAG) injection, a successful EOR method for clastic and carbonate reservoirs. WAG is characterized by an alternating sequence of drainage and imbibition cycles. Hysteresis is hence common and results in trapping of the non-wetting phase, which impacts incremental recovery. The competition of trapping and geological heterogeneity during WAG, particularly in carbonate reservoirs, is not yet fully understood.

In this study, we therefore use a high-resolution simulation model of a Jurassic Carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D formation in Qatar, to investigate the impact of non-wetting phase trapping during miscible and immiscible WAG in heterogeneous carbonate formations. We then compare the impact of trapping on recovery to the impact of heterogeneity in wettability and reservoir structure. We test end-member wettability scenarios and multiple rock types. We also compute effective fracture permeabilities using discrete fracture networks (DFN), ranging from sparsely distributed background fractures to fracture networks where intensity varies with proximity to faults.

The results enable us to analyse and compare WAG efficiency in carbonate reservoirs by ranking the impact of physical displacement processes (imbibition, drainage, trapping, miscibility) versus heterogeneity (wettability, faults, fractures, layering) that are typical for carbonate reservoirs. We show that while miscible WAG injection gives better displacement results than immiscible WAG injection or water flooding for this reservoir, recovery efficiency is limited by structurally induced bypassing and flow channelling. This bypassing is magnified if fractures are considered, leading to an earlier breakthrough of injected fluids and ultimate recoveries that are at least 8% lower compared to matrix-only models. We also demonstrate the impact of different hysteresis models and show that when irreversibility of the drainage and imbibition scanning curves during WAG is accounted for, trapping is enhanced and at least a 5% increase in recovery is observed. This modelling approach, therefore, enables us to increase the reliability of WAG simulations by accounting for trapping and its interaction with wettability, miscibility, and geological heterogeneity in fractured carbonate reservoirs.
Representing Slow Foam Dynamics in Laboratory Corefloods for Enhanced Oil Recovery
Authors: Kapetas L. , van El W. A. , Rossen W. R.
Published: June 2014

On the laboratory scale, foam can be slow to come to steady state (local equilibrium). In fitting dynamic foam corefloods, if local equilibrium does not apply, it is essential to understand and fit the dynamics so that an accurate local-equilibrium model can be applied on the field scale. We report an attempt to represent slow foam dynamics using a simple first-order kinetic expression for the approach of foam to steady state in a population-balance model. In particular, we attempt to fit a case of gas injection into a surfactant-saturated core ("SAG" injection) (Ma et al., 2013), where the peak in pressure difference across the core takes place well after gas breakthrough, in violation of most local-equilibrium foam models. As the kinetics of foam generation are slowed in our model, the peak pressure gradient is reduced, but the timing of the peak remains at the time of gas breakthrough, i.e. after less than one pore volume injection. For sufficiently slow kinetics, the peak can be broadened significantly by spreading of the traveling wave at the shock at the foam front.

We survey published population-balance models for mechanisms that could give a late peak in pressure gradient in a SAG coreflood. Most previous studies with population-balance models use parameter values that would give rapid foam generation and a peak in pressure drop at gas breakthrough in a SAG coreflood. The data of Ma et al. suggest an abrupt onset of foam generation later in the coreflood. To represent it, we believe some sort of triggering mechanism for foam generation (for instance, pressure gradient) is needed in the population-balance model. Another possible mechanism leading to a late peak is a nonlinear response of gas relative permeability to gas trapping and refining foam texture.
A Hierarchical Model Calibration Approach with Multiscale Spectral-Domain Parameterization: Application to a Structurally Complex Fractured Reservoir
Authors: Kang SukSang , Bhark Eric , Datta-Gupta Akhil , Kim JangHak , Jang IlSik
Published: June 2014

A hierarchal history matching algorithm is proposed that sequentially calibrates reservoir parameters from the global-to-local scale in consideration of parameter uncertainty and the resolution of the data. Parameter updates are constrained to the prior geologic heterogeneity and are performed parsimoniously, or only to spatial scales that can be resolved by the historical data. In the first step of the workflow, a genetic algorithm (GA) is used to calibrate and assess the uncertainty in global parameters (e.g., regional fracture properties, aquifer strength) that influence reservoir energy and field-scale flow behavior. To identify the reservoir volume over which each parameter region is applied, a novel heterogeneity segmentation technique is developed from spectral clustering theory. After an ensemble of calibrated model realizations is identified using the GA, the ensemble is reduced via a cluster analysis to define a variance-preserving subset of the members for the second step of local, higher-resolution parameter calibration. Each member of the subset is calibrated to well-level phase rate and pressure data using a sensitivity-based scheme. To improve the ill-posedness of each high-resolution inverse problem, the heterogeneity field is parameterized in the spectral domain using the Grid Connectivity-based Transform (GCT) to provide a compressed representation that captures only the sensitive geologic trends. The GCT concurrently imposes geological continuity during calibration and promotes minimal changes to each prior ensemble member.

The proposed calibration workflow is applied to a structurally complex, fractured reservoir located offshore Peru. The reservoir is modeled as dual porosity and single permeability (DPSP). In the global calibration step, the field water production rates, gas rates and average reservoir pressure are matched using the GA together with zonal multipliers that represent spatial variation in aquifer strength, fracture porosity and a matrix-fracture coupling parameter. In the subsequent local step, the well-by-well production histories are matched through calibration of the most uncertain grid-cell parameter, fracture permeability, which is characterized using the GCT parameterization. The final calibrated models are consistent with geologic interpretation and are currently being applied for field development strategies.
Solvent Enhanced Steam Drive
Authors: Hedden Ralf , Verlaan Marco , Lastovka Vaclav
Published: June 2014

In recent years the addition of a hydrocarbon solvent (usually in the range of C4 to C20) to Cyclic Steam Stimulation (CSS) or Steam Assisted Gravity Drainage (SAGD) operations in heavy oil (bitumen) reservoirs has become an attractive process. We extend the idea of solvent addition to steam to a Vertical well Steam Drive (VSD), and investigate the recovery mechanisms, impact on the ultimate recovery and oil steam ratio. The process is studied in core flooding experiments and a CT scanner was used to monitor the saturation distribution over time. These results are history matched using Shell's in-house numerical reservoir simulator MoReS. The simulations show that the dominant recovery mechanism is facilitated through the formation of a solvent bank. Accurate modeling and understanding of the recovery mechanism enables optimal design of the solvent co-injection process in a vertical well steam drive. This allows a comparison between a VSD and a CSS development using solvent addition to steam and selection of the best development option for a given reservoir.
CO2 Low Salinity Water Alternating Gas: A New Promising Approach for Enhanced Oil Recovery
Authors: Dang Cuong. T. , Nghiem Long. X. , Chen Zhangxin , Nguyen Ngoc. T. , Nguyen Quoc. P.
Published: June 2014

It has been recognized that there are significant advantages on combining low salinity waterflooding (LSW) with other enhanced oil recovery (EOR) techniques such as polymer or low tension surfactant flooding. This paper proposes a novel concept of low salinity water-alternating-CO2 (CO2 LSWAG) injection under CO2 miscible displacement conditions. While LSW is an emerging EOR method based on alteration of wettability from oil-wet to water-wet conditions, WAG is a proven method for improving gas flooding performance by controlling the gas mobility. Therefore, LSWAG injection promotes the synergy of the mechanisms underlying these methods (i.e., ion-exchange, wettability alteration, and CO2 miscible displacement and mobility control) that further enhances oil recovery and overcomes the late production problem frequently encountered in the conventional WAG. These features are demonstrated in this work based on a field case study.

To investigate the advantages of CO2 LSWAG, a comprehensive ion exchange model associated with geochemical processes has been developed and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. Laboratory core flood simulations of different CO2 LSWAG schemes are conducted to understand the combined effects of solubility of CO2 in brine, dissolution of carbonate minerals, ion exchange, and wettability alteration. CO2 LSWAG performance is then evaluated on a field scale through an innovative workflow that includes geological modeling, multi-phase multi component reservoir flow modeling and process optimization. The simulation results indicate that CO2 LSWAG has the highest oil recovery compared to conventional high salinity waterflood, high salinity WAG, and low salinity waterflood. A number of geological realizations are generated to assess the geological uncertainty effect, in particular clay distribution uncertainties, on CO2 LSWAG efficiency. Finally, CO2 LSWAG injection strategies are optimized by identifying key WAG parameters.

The proposed workflow demonstrates the synergy between CO2 WAG and LSW. Built in a robust reservoir simulator, it serves as a powerful tool for screening, design, optimization, and uncertainty assessment of the process performance from laboratory to and field scales. CO2 LSWAG is a promising EOR technique as it not only combines the benefits of CO2 injection and low salinity water floods but also promotes the synergy between these processes through the interactions between geochemical reactions associated with CO2 injection, ion exchange process, and wettability alteration. This paper demonstrates the merits of this process through modeling, optimization and uncertainty assessment.
Conformance Improvement Using Polymer Gels: A Case Study Approach
Authors: Lantz M. , Muniz G.
Published: June 2014

Poor conformance is a problem that has plagued most operators of water and enhanced oil recovery (EOR) floods. Conformance improvement has been shown to significantly improve oil recovery; however, effectively selecting and implementing the correct conformance improvement technique still remains a complicated proposition. The selection of the correct technique is only becoming even more important as the industry advances EOR floods where it is critical in these capital intensive projects to effectively sweep the reservoir.

Traditionally many operators have relied on mechanical or cement solutions to deal with poor conformance. Although these methods certainly have their place in conformance engineering they deal more with wellbore issues rather than reservoir flow dominated situations. The latter situation can be characterized as flow through highly conductive reservoir features such as fractures or highly permeable thief zones. In such situations it is advantageous to use a technology that can penetrate into the offending feature providing sustainable results. In water or EOR floods, the treatment of injection wells with polymer gels has been shown to be an effective technology in addressing such reservoir conformance issues. Extensive research has gone into characterizing polymer gels and numerous field case studies have been published. However, few references aid in understanding when polymer gels should be used and the critical aspects of designing and implementing such treatments.

This paper will focus on diagnosing those conformance issues where it is most appropriate to use polymer gels. Further, it will explain how reservoir characterization should drive the design and implementation of this technology. Four injection well case studies will be used to develop a Polymer Gel Conformance Improvement Matrix that will provide heuristics for designing a polymer gel treatment. Finally, lessons learned from the case studies will be presented to give guidance on diagnosing conformance issue along with the design and implementation of conformance improvement polymer gel treatments.