bluuebunny/crossref_metadata_2025_split huggingface dataset:
Applying Horizontal Wells to Develop Oilfields with Complex Low Relief Structure in High Water Cut Stage in Tarapoa
Authors: Zhang Haikuan , Zhang Xing , Zhao Xinjun , Hu Quan , Wan Xuepeng , Serrano Fabrizio , Zhang Kexin , Lei Zhanxiang , Wang Yusheng 
Published: November 2015

Abstract
The feasibility of horizontal well technology is analyzed for the M1 reservoir of the Tarapoa Block. Applying advanced location deployment technologies of horizontal well, and optimizing key parameters are aimed to expand the application scale of horizontal wells in the Tarapoa Block.
The approach is based on the research of genetic model of lithologic reservoirs, reservoir distribution characteristics and remaining oil distribution. The successful application of using combined drilling and completion technologies is already confirmed, and methods are described which focus on key parameters for optimizing horizontal well drilling and completion technology.
From 2006 to 2014, nearly 67 wells have been successfully put on production on Tarapoa Block. According to petrogenesis, remaining oil of micro-structural type and well pattern imperfect type in M1 sandstone are major potential areas of applying horizontal technology. Because most wells are in a high water cut phase with thin net pays and bottom water drive, the optimal horizontal segment position, horizontal section length and well flow regime, need to be studied in order to ensure its economic benefit. Studies suggest that the relative height of the horizontal section to avoid bottom water should be more than 70%. Due to the small size of the remaining microstructures for the M1 reservoir, the longer the horizontal section, the greater the difficulty for controlling the trajectory. Considering that the produced water needs to be treated, the initial fluid volume of the horizontal wells should be controlled.
Horizontal well technology in the Tarapoa Block has been successfully applied. Horizontal wells have accounted for 44% of the production of all new wells during the period and production from horizontal wells is 2.75 times that of the directional wells. They play a key role in stabilizing oil production, slowing declines and maintaining water control.
Experimental Investigation of Polymer Assisted WAG for Mobility Control in the Highly Heterogeneous North Burbank Unit in Oklahoma, Using Anthropogenic CO2
Authors: Tovar Francisco D. , Barrufet Maria A. , Schechter David S. 
Published: November 2015

Abstract
This work investigates the use of polymers during CO2 WAG using a physical model. Coreflooding experiments were conducted to compare polymer assisted WAG, conventional WAG, continuous CO2 flooding, and polymer flooding. The effect of miscibility in the CO2 – oil interface was evaluated from coreflooding at two different pressures, above and below the MMP of 1563 psig The MMP was experimentally determined using a fast version of the slim tube procedure with a shorter column. The influence of reservoir heterogeneity was observed by conducting corefloodings in homogeneous and heterogeneous rocks with permeability ranging from 13 to 1300 md. The core plugs were selected using computed tomography to ensure the presence or absence of heterogeneous features.
Our results show that under miscible displacement in a homogeneous rock, continuous CO2 injection can reduce residual oil saturation (Sor) to less than 10%, even for a permeability as low as 13 md. The implementation of conventional WAG and polymer assisted WAG in this case was detrimental for the process as water saturation shielded a portion of the oil preventing CO2 contact. The departure from the ideal miscible displacement resulted in a Sor as high as 32 %. For the heterogeneous rock, at 285 psig above MMP, the WAG CO2 was able to reduce Sor to as low as 11%, whereas at 260 psig below MMP a Sor of 23% was reached. As the level of heterogeneity increases, the oil recovery of polymer assisted WAG relative to conventional WAG increased suggesting that a certain degree of heterogeneity is needed for the polymer assisted WAG process to be beneficial. A throughout discussion on the recovery mechanisms and the interactive / combined role of miscibility, heterogeneity, permeability and viscosity is presented.
This work adds to the understanding of the CO2 flooding process implemented in the North Burbank Unit (NBU) and the potential to use WAG and polymer assisted WAG to improve mobility control. Sweep efficiency is the most important challenge from a reservoir engineering standpoint for CO2 flooding, but it is particularly critical in the NBU for two reasons. The high vertical heterogeneity in the field, with a permeability variation of three orders of magnitude within 30 ft of reservoir thickness, which greatly exacerbates viscous fingering, and the use of anthropogenic CO2 which makes the economics of the project more sensitive.
Estimates of Stress Dependent Properties in Tight Reservoirs: Their Use with Drill Cuttings Data
Authors: Lopez Bruno , Piedrahita Jaime , Aguilera Roberto 
Published: November 2015

Abstract
The objective of this paper is to present a methodology using drill cuttings for making estimates of porosity, permeability and compressibility as a function of confining pressures in tight formations.
An easy to use correlation is developed by comparing results from experimental work including hysteresis at various combinations of overburden and pore pressures in vertical and horizontal core plugs, and permeabilities and porosities determined in the laboratory from drill cuttings. The work is important because of the presence of stress-dependent slot and/or microfracture porosities and permeabilities in tight formations that can affect significantly reservoir performance and forecasting.
Recent work has shown that drill cuttings can be used quantitatively for complete petrophysical evaluation (for example determination of porosity, water saturation, pore throat aperture, Young Modulus, Poisson's ratio and brittleness index (Olusola and Aguilera, 2013; Ortega and Aguilera, 2014). The methods have been shown to be useful in those instances where cores and specialized well logs are scarce. Those methodologies are extended in this paper to quantitative evaluation of stress dependent properties.
It is concluded that drill cuttings are important direct sources of information that can be used for developing estimates of stress-dependent properties particularly in those cases where cores and specialized logs are scarce or not available. The methodology and correlation are presented in detail as well as a practical application. Although the main and novel contribution is the development of an easy to use correlation for stress-dependent tight reservoirs using drill cuttings, the correlation can obviously be used if only plug data are available.
An Approach for Steam Propagation and Production Performance in SAGD and Solvent SAGD: Lab Experiment and Simulation
Authors: Zare A. , Hamouda A. A. 
Published: November 2015

Abstract
Steam Assisted Gravity Drainage (SAGD) is considered a successful EOR method for heavy oil and bitumen.
A two-dimensional physical model is designed to conduct experiments in this study. The consistency of the experimental data obtained was tested. The designed model was instrumented with 15 temperature sensors at different locations aimed at capturing the temperature propagation with distance and time. The experimental consistency tests for stream propagation have helped in understanding the important controlling parameters for the experiments. Steam propagation was mapped to understand the various processes taking place for oil recovery from steam chamber size and shape. The recovery mechanism could, to some extent, be realised.
A simulation approach has been developed to history-match the production, and is compared to the used approach in the literature. Numerical simulation of the effect of Solvent SAGD on EOR was investigated. The developed steam chamber by simulated Solvent SAGD, simulated and experimental SAGD, is addressed in the paper. The results present an excellent practical approach to obtaining a developed steam chamber and accordingly identifying mechanisms. The match quality of the history-matched experiment allows a good assessment for production forecast, with understanding and development of the process.
The paper contributes to generating more in-depth understanding of heat propagation, chamber development, and the heat transfer mechanism of SAGD.
Synergism Between Ionic and Nonionic Surfactants for Producing Low Interfacial Tension at Oil-Water Interface
Authors: Martiz A. , Samaniego S. , Aray Y. , Paredes R. 
Published: November 2015

Abstract
The synergism of mixtures of anionic and non-ionic surfactants adsorbed at the water/alkane interface was studied using mesoscopic Dissipative Particle Dynamic simulations. The effect of the mixtures of sodium m, p-exylbenzenesulfonate and sodium m, p-octylbenzenesulfonate with the nonionic surfactant lauryl alcohol polyoxyethylene (9) ether on the surface tension of the water/alkane interface was explored. Alkane scanning curves for n-alkanes from hexane to tetradecane are reported. Our results suggest that dissolution of lauryl alcohol polyoxyethylene (9) ether in the hydrocarbon phase is the origin of this behavior. For the sodium m, p-octylbenzenesulfonate case, the mixture with lauryl alcohol polyoxyethylene (9) ether induces a synergism for alkanes with low carbon number. A moderate lipophilic behavior of the mixture was observed for hexane and as a result 95% of the mixture stays at the interface forming a really compact layer at the interface. Additionally, increase on the carbon number alkane produces an increase in the hydrophilic behavior of lauryl alcohol polyoxyethylene (9) ether inducing higher interfacial tension values.
Effect of Oil and Gas Prices on Unconventional Resource Plays
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: November 2015

Abstract
The objective of this paper is to examine the effect of oil and gas prices on the development of tight and shale reservoirs including oil, gas and condensate.
The methodology uses a variable shape distribution (VSD) model for examining past, present and futures prices of oil and gas. The VSD matches historical annual changes in oil and gas prices with coefficients of determination that are generally larger than 0.98. Contrary to several commentators and specialized organizations around the world that were forecasting continuous oil price escalation up to US$ 300/bbl (e.g. in 2008, when the oil price was around US$ 140/bbl), the VSD was used successfully to anticipate a significant drop in prices, leading to the on-record statement that the oil price was a bubble and was going to burst (June 13, 2008).
The VSD was also used to build a case at LACPEC in 2014 (Aguilera and Aguilera, 2014) indicating that "with the vast global oil resource base and the significant technological advances being implemented by the industry, oil prices could actually decrease in the future". This is a painful fact being faced today by the oil and gas industry worldwide.
In this paper, the VSD has been used with a global energy market (GEM) model to examine possible future outcomes of unconventional resources development in light of forecasted oil and gas demand and anticipated price-changes calculated with the VSD.
The methodology provides a novel approach for examining some realistic possibilities regarding future development of unconventional oil, gas and condensate reservoirs.
Experimental Study of Heavy Oil In-Situ Upgrading Using High Temperature Gas-Oil Gravity Drainage in Naturally Fractured Reservoirs
Authors: Suarez Ricardo G. , Scott Carlos , Hejazi S. Hossein , Pereira-Almao Pedro 
Published: November 2015

Abstract
Heavy oil recovery from matrix blocks of Indiana limestone and Silurian dolomite core samples was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Core samples and fractures were respectively saturated with heavy oil and gas. Oil recovery experiments were conducted in batch-mode using two different gases, nitrogen and carbon dioxide, at 1000 psi and various temperatures (200, 250, and 300 °C). N2 was employed as an inert gas to study the effect of temperature in oil production from the cores without affecting its chemical properties. Consequently, CO2 was used to investigate the role of mass transfer between matrix and fracture fluids in oil recovery.
The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the remaining oil in the core was extracted. Viscosity determinations and simulated distillations of the two samples, produced oil and remained oil in the core, were carried out in order to assess oil quality distribution.
Experimental results revealed that with immiscible gas injection at high temperatures oil segregation occurred in the porous media. Consequently, lighter components of oil were produced while the heavier ones were left behind inside the matrix. Results also demonstrated a relationship between the amount of oil produced and the oil segregation in the porous media.
This research provides a systematic analysis to investigate the main recovery mechanisms from carbonate matrix blocks under various hot gas injection scenarios, which is of great interest to determine the most appropriate enhanced recovery method to be applied for heavy oil production from naturally fractured reservoirs.
Design and Implementation of the First Polymer Flooding Project in Colombia: Yariguí-Cantagallo Field
Authors: Maya G. , Jimenez R. , Castro R. , Mantilla J. , Vargas J. , Cardenas F. , Fernandez F. , Quintero H. , Zaitoun A. , Manrique E. , Romero J. , Putnam J. 
Published: November 2015

Abstract
Waterflooding is one of the oil recovery processes best known and applied worldwide. However, this method has limited efficiency to displace oil. That is why the implementations of chemical Enhanced Oil Recovery (CEOR) processes is necessary, with the objective of increasing both volumetric and displacement efficiencies and maximize the recovery factor, even at the early stages of waterflooding.
The first Polymer flooding Project of ECOPETROL S.A. spent 18 months designing and assuring the stages of screening, area selection, experimental feasibility, numerical simulation, infrastructure, financial analysis, automation, execution and online monitoring of a polymer flooding EOR pilot in the Yariguí-Cantagallo field. Strategically, the pilot has two injection patterns operated by two different globally recognized services companies.
The first injection pattern started on 17 March 2014 with an injection rate of 1,000 BPD and a polymer concentration of 1,500 ppm in YR-504 injection well. The second injection pattern began on 27 April 2014 with the same injection rate and a polymer concentration of 800 ppm in YR-510 injector.
The first seventeen months of polymer injection have allowed the assimilation of learned lessons, best practices for continual improvement in the operation of such processes, incremental oil production; water cut reduction and increases in the fluid levels for the first row of offset producers. The development of the first polymer flooding pilot in Colombia by Ecopetrol broadens the expectations for expansion in the field and implementing this type of technology to other Colombian oil fields, and has become one player to leverage the achievement of production goals of the business group.
This work presents the implemented procedure during design, execution and initial monitoring of the polymer flooding project, which is the first project of its kind carried out in Colombia by Ecopetrol and can be considered successful at a cost per incremental barrel of $US 4.60.
Designing a Development Plan with a Constrained Multi-Layered Reservoir Model Using Pressure Transients and Downhole Fluid Analysis
Authors: Dubost F. X. , Rocha M. , Lavin L. M. , Fuentes R. , Ramirez J. R. , Guzman D. 
Published: November 2015

Abstract
A new method is presented to assess layer connectivity and determine dynamic reservoir properties for use as inputs in a numerical model for a multi-layered reservoir. Large scale formation tester transient measurements and downhole fluid analysis information are used to construct the reservoir model. Pressure and fluid measurements distributed vertically at the wellbore and laterally in different wells are used to delineate the sands and model the complex fluid behaviors. Pressure transients recorded in different wells from a wireline formation tester (WFT) in small scale drill stem test (DST), or from conventional well tests, are then used to constrain the dynamic model properties through a grid-based inversion technique, so that observed test data and the model response match.
Our workflow consists in constructing initial reservoir models using the acquired log and test data, and constraining the model properties to the transient test data. Wireline conveyed tests and downhole fluid analysis (DFA) measurements from different wells are inputs to the geomodel, and building steps to assess layer connectivity from pressure gradient and fluid matches. Then a fluid model equation of state (EOS) is built from PVT experiments on the fluids in the laboratory, and tuned to the observed changes against depth in the fluid properties from downhole measurements, such as solution gas-oil ratio or saturation pressures. Initial dynamic layer properties, such as horizontal and vertical permeabilities are typically obtained from logs and cores. In our workflow we calibrate these properties to interval pressure transient tests (IPTT) and conventional well tests. These modeled properties are constrained to match the IPTT or well tests. An optimization routine is conducted, using adjoint simulations, to minimize an objective function composed of observed bottomhole pressures given different flowrates during a transient test and the pressure response of the model. In this optimization step, the skin values are introduced explicitly in the model, but the dynamic properties are modified until a match is obtained. Once the model is constrained, it is then used to develop an optimum development strategy.
We present a case study to illustrate our methodology, in a new field development setting, with transient tests and WFT measurements acquired in three different appraisal wells, which traverse multiple channel sands reservoirs. These tests were used to build an optimal model which respected all acquired measurements. We finally show how this calibrated model was used to help make a decision about the development strategy.
A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs
Authors: Orozco Daniel , Aguilera Roberto 
Published: November 2015

Abstract
During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara and Marcellus shale plays in the US. This paper presents a new Material Balance Equation (MBE) for estimation of Original Gas in Place (OGIP) and Original Condensate in Place (OCIP) in shale gas condensate reservoirs. This material balance methodology allows estimating the critical time for implementing gas injection in those cases where condensate buildup represents a problem. Additionally, the proposed MBE considers the effects of free, adsorbed and dissolved gas condensate production, and also takes into-account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically re-fracturing shale condensate reservoirs.
The new MBE applies to shale gas condensate reservoirs by incorporating a two-phase gas deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas condensate reservoir, a single straight line is obtained. However, when the single-phase gas compressibility factor (Z) is used, a deviation from the linear behavior is observed once the reservoir pressure falls below the gas dew-point. This methodology is applied in this study to unconventional shale gas condensate. Since there are three characteristic stages of production in a shale gas reservoir (production of free, adsorbed and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is located in the region where production of free gas is predominant, then the production due to desorption mechanisms will be negatively impacted because condensation will have already occurred in the reservoir, resulting on reduction of effective permeability to gas. This methodology allows then estimating the critical time for implementing gas injection on the basis of the total cumulative gas production.
Results are presented as crossplots of 1) P/Z2 vs. Gpt, 2) Gpt vs. time and 3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale gas condensate reservoirs where condensate buildup represents a threat that can negatively impact the gas production rate.
The novelty of this work resides on the fact that the combined effect of free, adsorbed and dissolved gas production mechanisms on stress-sensitive shale gas condensate reservoirs has not been considered previously in the literature for estimation of OGIP and OCIP using an analytical MBE.
New Seismic Base Reservoir Characterization (SBRC) Geomechanical Model Based on Mogi Empirical Rock Failure Relationship
Authors: Li Qi , Yousefzadeh Adam , Aguilera Roberto 
Published: November 2015

Abstract
The objective of this paper is to develop a seismic based reservoir characterization (SBRC) geomechanical model using a non-linear relationship between the maximum and minimum principal stress and taking into account the intermediate principal stress.
The proposed geomechanical model is constructed based on Mogi's (1967) empirical rock failure relationship. This allows introducing for the first time in the SBRC the intermediate principal stress. In order to do it, in-situ stress variations as a function of depth are used to match failure stresses for five groups of rock failure experiments that have different values of least principal stress. Next the relationship is integrated with the diffusivity equation for estimating large-scale permeability.
German Continental Deep Drilling Project (KTB) data are used to test the validity of the new SBRC model. Two ‘hydraulic fracturing’ depths (9100 and 6360m) in the KTB site are used to demonstrate the methodology. Minimum permeabilities are calculated with the new SBRC to be 2.9×10−20 m2 at 6360 m and 3.1×10−20 m2 at 9100 m. Maximum permeabilities are 2.3×10−16 m2 at 6360 m and 2.9×10−16 m2 at 9100m. Thus the maximum permeability is approximately 4 orders of magnitude larger compared with the minimum permeability (1 m2 = 1.013E15 md).
Novelties of the approach can be summarized as follows: (1) the use of Mogi's (1969) empirical rock failure relationship for integrating intermediate principal stress into the SBRC geomechanical model (this cannot be done when using for example the Mohr-Coulomb rock failure criterion), (2) using a nonlinear relationship between the maximum and minimum principal stress and (3) calculating large-scale permeability.