bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Simple Transient Flow Model for MPD and UBD Applications
Authors: Udegbunam John Emeka , Fjelde Kjell Kåre , Evje Steinar , Nygaard Gerhard 
Published: June 2014

Abstract
Transient flow models play an important role in the planning and follow-up of advanced well operations such as managed pressure drilling and underbalanced operations. The most recent trend is a situation whereby flow models and control engineering algorithms are combined in various settings, to control flow parameters. This requires robust flow models and an in-depth understanding of uncertainties in the modeling process.
This paper presents a simple and robust transient model that can handle highly dynamic flow systems. The model, AUSMV scheme, has been developed for academic and training purposes. With the model, students can investigate different flow scenarios and pressure control challenges encountered in general well control, managed pressure drilling, underbalanced drilling, and automation.
The capability of this model to handle highly changing flow scenarios will be demonstrated with examples taken from managed pressure drilling and underbalanced operations. The effect of numerical dissipation on the model predictions will be briefly discussed.
Pressure Normalization of Production Rates Improves Forecasting Results
Authors: Lacayo Juan , Lee John 
Published: June 2014

Abstract
Recently, as a result of the increasing exploration and production activity in unconventional plays, new decline curve models have been developed. The main purpose of these newer models—e.g., SEPD, Duong, Logistic Growth, Power Law, Dual-Models—is to overcome the boundary-dominated flow assumption required for validity of the basic Arps’ model, which restricts its application in ultra-low permeability reservoirs exhibiting long-duration transient flow. These new decline curve analysis (DCA) methods are still ordinarily applied only to rate-time data, and thus rely on the assumption of stable (constant) flowing pressure. Since this stabilized state is not reached rapidly in most unconventional wells, the applicability of these methods and the reliability of their forecasts may be compromised. In addition, production performance predictions cannot be disassociated from the operational constraints that existed when production history was observed.
This paper introduces a modified decline curve analysis method we call Pressure Normalized Decline Curve Analysis (PN-DCA) to provide a solution to these problems. Unlike traditional DCA methodology, which analyzes only production rates, this method analyzes pressure-normalized rates. To validate the applicability of this technique, we used hindcasting analysis of real production data from four different shale plays in the US (Eagle Ford, Woodford, Marcellus and Bakken). We found that this technique can be used as a reliable production forecasting technique suited to interpret unconventional well data in specific situations such as unstable operating conditions, limited availability of production data (short production history), and high-pressure, rate-restricted wells. Moreover, this method has proved to have the important ability to dissociate the estimation of future production performance from past operation constraints.
This work also proposes an innovative decline curve analysis workflow, which includes a multi-method approach to optimize the flow regimes identification process. This methodology integrates different diagnostic plots that have been improved by incorporating important concepts such as MBT, pseudo-variables (for gas wells) and pressure-normalized rates. Each DCA model has been designed assuming specific flow regimes. Therefore, a proper identification of dominant flow regimes will help us to perform decline curve analyses with more confidence and to avoid unrealistic production forecasts.
In general, incorporating pressure-normalized rates in decline curve analysis offers the possibility of producing improved forecasting results, which implies greater accuracy in production performance predictions and more reliable reserves estimations. The petroleum industry may become more confident in reserves estimates, which are the basis for the design of development plans, investment decisions, and valuation of companies’ assets.
Improvement of Eagle Ford Shale Formation's Water Imbibition by Mineral Dissolution and Wettability Alteration
Authors: Morsy Samiha , Gomaa A. , Sheng J. J. 
Published: June 2014

Abstract
In order to understand the performance of waterflooding in 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. Reservoir core samples from Eagle Ford shale 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 porosity of the used samples using CT Scanning. The average porosity was 1.6% for Eagle Ford shale samples. Secondly, we studied the rock stability and spontaneous imbibtion of the different Eagle Ford 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 37% for Eagle Ford using pH 0.74 (3 wt% HCl in 2 wt% KCl) and 44% using pH 11.7 (0.1 wt% NaOH in distilled water). The oil recovery was improved by mineral dissolution using low and high pH solutions along with wettability alteration. The rock hardness was significantly affected by using both high and low pH solutions, which resulted in 93-98% loss of its initial value.
From Streamlines to Fast Marching: Rapid Simulation and Performance Assessment of Shale Gas Reservoirs Using Diffusive Time of Flight as a Spatial Coordinate
Authors: Zhang Yanbin , Bansal Neha , Fujita Yusuke , Datta-Gupta Akhil , King Michael J. , Sankaran Sathish 
Published: June 2014

Abstract
Current industry practice for characterization and assessment of unconventional reservoirs mostly utilizes empirical decline curve analysis or analytic rate and pressure transient analysis. High resolution numerical simulation with local PEBI grids and global corner point grids has also been used to examine complex non-planar fracture geometry, interaction between hydraulic and natural fractures and implications on the well performance. While the analytic tools require many simplified assumptions, numerical simulation techniques are computationally expensive and do not provide the more geometric understanding derived from the depth of investigation and drainage volume calculations.
We propose a novel approach for rapid field-scale performance assessment of shale gas reservoirs. Our proposed approach is based on a high frequency asymptotic solution of the diffusivity equation in heterogeneous reservoirs and serves as a bridge between simplified analytical tools and complex numerical simulation. The high frequency solution leads to the Eikonal equation which is solved for a ‘diffusive time of flight’ that governs the propagation of the ‘pressure front’ in the reservoir. The Eikonal equation can be solved using the Fast Marching Method to determine the ‘diffusive time of flight’, which generalizes the concept of depth of investigation to heterogeneous and fractured reservoirs. It provides an efficient means to calculate drainage volume, pressure depletion and well performance and can be significantly faster than conventional numerical simulation. More importantly, in a manner analogous to streamline simulation, the ‘diffusive time of flight’ can also be used as a spatial coordinate to reduce the 3-D diffusivity equation into a 1-D equation, leading to a comprehensive simulator for rapid performance prediction of shale gas reservoirs (Patent Pending, 2013). The speed and versatility of our proposed method makes it ideally suited for high resolution reservoir characterization through integration of static and dynamic data.
The major advantages of our proposed approach are its simplicity, intuitive appeal and computational efficiency. We demonstrate the power and utility of our method using a field example that involves history matching, uncertainty analysis and performance assessment of a shale gas reservoir located in East Texas. A sensitivity study is first carried out to systematically identify the ‘heavy hitters’ impacting the well performance. This is followed by a history matching and uncertainty analysis to identify the fracture parameters and the stimulated reservoir volume. A comparison of model predictions with the actual well performance shows that our approach is able to reliably predict the pressure depletion and rate decline.
Understanding Shale Performance: Performance Analysis Workflow with Analytical Models in Eagle Ford Shale Play
Authors: Samandarli Orkhan , McDonald Beth , Barzola Gervasio , Murray Mark , Richmond Perry 
Published: June 2014

Abstract
Tight oil and shale gas resources produced 29% of total US crude oil and 40% of total US natural gas in 2012 (EIA). Technically recoverable quantities of shale gas and shale oil resources for the US are 665 trillion cubic feet and 58 billion barrels, respectively. Considering the impact of the "unconventional boom" on the economy, it is crucial to understand the production performance of wells to maximize the recovery from shale plays.
The latest advances in Rate Transient Analysis (RTA) provide quick yet robust tools to assess the quality of the Stimulated Rock Volume (SRV) and long term performance of the wells by estimating EURs. The most common challenge in history-matching of production in shale gas/oil wells has been the non-uniqueness of the history-matched parameters. A lot of emphasis has been put on estimation of fracture half-length, which is believed to be a primary driver for the performance of shale gas/oil wells.
Since linear flow is the main transient flow regime in the early life of a hydraulically-fractured shale gas/oil well, a Rate Normalized Pressure (RNP) versus Square Root of Time plot is the most commonly used diagnostic plot for the performance analysis of the wells. A*sqrt(k) or xf*sqrt(k) parameter groups are reported as a proxy for productivity in hydraulically fractured shale/gas oil wells. Besides having permeability as an unknown, the history-match is also sensitive to net hydraulic fracture height, which is one of the inputs to models that must be specified from other sources of information.
This paper presents a novel approach for production performance analysis of shale gas/oil wells, which significantly reduces the non-uniqueness issues that one can have in comparison of performance. Twenty two Eagle Ford Shale wells were analyzed across the trend from lean gas to high-yield condensate to define a workflow that could be applied to other wells in different geologic areas, yet provide consistent comparison of long term performance (EURs).
Field vs Laboratory Polymer Retention Values for a Polymer Flood in the Tambaredjo Field
Authors: Manichand R. N. , Seright R. S. 
Published: June 2014

Abstract
During a polymer flood, polymer retention can have a major impact on the rate of polymer propagation through a reservoir, and consequently, on oil recovery. A review of the polymer-retention literature revealed that iron and high-surface-area minerals (e.g., clays) dominate polymer retention measurements in permeable rock and sand (&gt;100 md). A review of the literature on inaccessible pore volume revealed inconsistent and unexplained behavior. A conservative approach to design of a polymer flood in high-permeability (&gt;1 darcy) sands would assume that inaccessible pore volume is zero. Laboratory measurements using fluids and sands associated with the Sarah Maria polymer flood in Suriname suggested polymer retention and inaccessible pore volume values near zero. A procedure was developed using salinity-tracer and polymer concentrations from production wells to estimate polymer retention during the Sarah Maria polymer flood in the Tambaredjo reservoir. Field calculations indicated much higher polymer retention values than lab tests, typically ranging from ~50 to 250 μg/g. Field cores necessarily represent an extremely small fraction of the reservoir. Because of the importance of polymer retention, there is considerable value in deriving polymer retention from field results, so that information can be used in the design of project expansions.
Field vs. Laboratory Polymer-Retention Values for a Polymer Flood in the Tambaredjo Field
Authors: Manichand R.N.. N. , Seright R.S.. S. 
Published: June 2014

SummaryDuring a polymer flood, polymer retention can have a major impact on the rate of polymer propagation through a reservoir, and consequently on oil recovery. A review of the polymer-retention literature revealed that iron and high-surface-area minerals (e.g., clays) dominate polymer-retention measurements in permeable rock and sand (&gt;100 md). A review of the literature on inaccessible pore volume (IAPV) revealed inconsistent and unexplained behavior. A conservative approach to design of a polymer flood in high-permeability (&gt;1 darcy) sands would assume that IAPV is zero. Laboratory measurements using fluids and sands associated with the Sarah Maria polymer flood in Suriname suggested polymer retention and IAPV values near zero [0±20 μg/g for retention and 0±10% pore volume (PV) for IAPV]. A procedure was developed using salinity-tracer and polymer concentrations from production wells to estimate polymer retention during the Sarah Maria polymer flood in the Tambaredjo reservoir. Field calculations indicated much higher polymer-retention values than those from laboratory tests, typically ranging from approximately 50 to 250 μg/g. Field cores necessarily represent an extremely small fraction of the reservoir. Because of the importance of polymer retention, there is considerable value in deriving polymer retention from field results, so that information can be used in the design of project expansions.
Design, Implementation and Early Operating Results of Steam Injection Pilot in already CO2 Flooded Deep-Heavy Oil Fractured Carbonate Reservoir of Bati Raman Field, Turkey
Authors: Sahin Secaeddin , Kalfa Ulker , Uysal Serkan , Kilic Harun , Lahna Hakki 
Published: June 2014

Abstract
With initial heavy-oil in place of 1.85 billion barrels, the Bati Raman Field (Turkey's largest oil deposition) was discovered and put on stream in 1961. The field hardly attained a primary recovery of ~2% due to the poor quality of the rock and fluid properties, and a low energy drive mechanism. An immiscible carbondioxide (CO2) flooding project commenced in 1986 and it has been successfully implemented for about a quarter of a century. Oil production, which was only 1,500 STB/D prior to this project, reached 14,000 STB/D within a few years, however, there has been a declining trend thereafter.
The project is still active and has added significant value to the field showing an increment of 3-4 times in the recovery factor. Nevertheless, the amount of CO2 required for one extra barrel of oil has a tendency to increase and the fact that the CO2 injection will soon complete its mission, remaining a considerably high amount of oil in the reservoir. Therefore, there is great incentive to implement another effective enhanced recovery process in the field to drain this remaining oil.
Currently, the field is under consideration for another marginal and unique application of enhanced oil recovery, of which no analogous application is yet known worldwide. A steam injection pilot in already CO2 flooded deep-heavy oil fractured carbonate reservoir has been initiated. There are a few similar applications, but their depths are incomparably shallower than the Bati Raman Field. The steam injection pilot with two injectors, one observer, and eleven producers at the crest was commenced in September 2012. The purpose was to heat and pressurize the reservoir from the top and produce oil from the neighboring producers. This paper documents the design, implementation, and early operational results of this pilot project.
Development of Small Molecule CO2 Thickeners for EOR and Fracturing
Authors: Lee J. J. , Cummings S. , Dhuwe A. , Enick R. M. , Beckman E. J. , Perry R. , Doherty M. , O'Brien M. 
Published: June 2014

Abstract
The ideal carbon dioxide (CO2) thickener would be an affordable, safe, water-insoluble additive that could dissolve in CO2 at typical wellhead and reservoir conditions during CO2 enhanced oil recovery (EOR) and elevate the viscosity of CO2 to the same value as the oil. Further, the additive would not require heating or an organic co-solvent to achieve dissolution. A CO2 thickener could be a transformative technology in that it would eliminate unfavorable mobility ratios during CO2 EOR and reduce or eliminate the need for WAG. A detailed history of prior attempts to thicken CO2 with either high molecular weight polymers or small associating compounds is presented. Our strategy for designing a novel small molecule CO2 thickener is then detailed. Each thickener candidate contains a strongly CO2-philic segment (e.g. a very short polymer or oligomer of silicone oil or polyprolylene glycol), and one or more somewhat CO2-phobic functional groups that induces intermolecular interactions that can lead to the formation of viscosity-enhancing supramolecular structures in solution.
Combining Conformance Treatment with Mobility Control Increases Enhanced Recovery Factor
Authors: Baker Richard , Lok Crystal , Stephenson Tim , Weghorn Steven 
Published: June 2014

Abstract
Mature water floods with high-permeability sands and medium to heavy-gravity crude oil are prime candidates for enhanced oil recovery (EOR) methods. We examined actual field results from the Buffalo Coulee reservoir. The simulation model was history matched on waterflooding and primary. Forecasts were performed with waterflooding and polymer flooding as well as gel treatments. Results indicated that polymer flooding resulted in a 5 to 8% incremental recovery factor over water flooding, while gel treatments resulted in a 2 to 4% incremental when applied separately. However, when gel treatments were performed immediately prior to polymer flooding, simulation showed the incremental recovery was much higher at 10 to 15%. In other words, there was a large synergistic effect of gels with polymers.
As seen from long-term production data, interwell tracer analysis, pressure pulse tests, and communication analysis, many waterfloods develop preferred water channels due to preferential flow pathways and/or waterflood-induced fracturing. These channels sometimes cycle large volumes of water from injectors to producers in waterfloods with very high water cuts. These channels also can significantly affect the chemical EOR process. Therefore, it is critically important to understand these preferential paths and flow mechanisms in the reservoir and then, in some cases, take corrective action before tertiary EOR is implemented.
Permanently plugging these water channels using crosslinked gel has some significant impacts on improving chemical EOR efficiency and waterflood efficiency. The synergistic effect of the combined treatment significantly improves chemical EOR economics by reducing chemical demand, increasing oil production, decreasing water production, and increasing volumetric sweep.
Injection Water Chemistry Requirement Guidelines for IOR/EOR
Authors: Ayirala S. C. , Yousef A. A. 
Published: June 2014

Abstract
Water chemistry with selective ionic content and composition in the injection water plays a critical role to impact on several oil recovery enhancement processes. Low ionic strength waters with threshold salinities lower than 5,000 ppm are desired for SmartWater flooding in sandstones. Low to moderate salinity waters depleted in monovalents, but enriched in sulfates and divalents are suited for SmartWater flooding in carbonates. Polymer floods mandate different low salinity water lacking both monovalent and divalent ions to reduce polymer dosage and improve project economics. ASP floods require optimal salinity water without the hardness ions to enable utilization of alkali and certain temperature tolerant surfactants in the chemical formulation design. Lower salinity water is desired for carbonated water flooding to increase CO2 dissolved quantities for better incremental oil recovery. Lower salinity waters could turn out to be a boon for even CO2 WAG where low salinity benefits outweigh the adverse CO2 solubility effects. Thermal floods require fresh and hardness free water to generate steam as injectant using boilers.
Injection waters of optimized salinity, ionic content and composition not only work on their own, but can also synergistically combine with other EOR processes to result in higher incremental oil recoveries. Lower salinity waters have a beneficial effect in polymer, surfactant, dilute surfactant and carbonated water floods to yield better oil recoveries when compared to high salinity water. In this paper we first provide an overview on the benefits of tuning injection water salinity and composition in different IOR/EOR processes with selected examples from published data and then propose a unique set of injection water chemistry requirement guidelines for IOR/EOR. The present study findings also point out the need to develop "water chemistry" as a specialty discipline within EOR portfolio and advocate for better integration of this emerging focus area with other key surface and subsurface related disciplines to effectively improve upon IOR/EOR upstream value chain.