bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Injection to Mitigate Condensate Banking in a Low-Permeability Reservoir
Authors: Evans Edward , Ghalambor Ali , Orangi Abdollah 
Published: January 2016

Abstract
One of the main challenges of producing tight or low-permeability gas reservoirs is condensate banking when production starts as the reservoir pressure drops below the dewpoint pressure. Condensate banking causes formation damage and subsequently damages production. The normal procedure to mitigate condensate banking is to hydraulically fracture the well to bypass the condensate bank and improve production from that well. Modeling the condensate banking along the hydraulic fracture is critical to understanding the loss of productivity.
We investigated the feasibility of simulating a cyclic CO2 injection scheme to mitigate formation damage due to gas condensate dropout in a low-permeability gas reservoir. The field was modeled using a tartan grid to be able to model the hydraulic fracture explicitly. In addition to the hydraulic fracture, the study examined how much of a role the condensate-gas ratio (CGR) plays in the condensate banking and how to best position a well in a low-, medium-, and high-CGR fluid. For the mitigation phase, different cyclic parameters such as injection rate, injection pressure, and soaking time for the cyclic CO2 injection were considered.
The study found that the volume of the GCR played a critical role in determining injection rates and pressure to best be able to mitigate damage due to condensate banking.
Enhancing a Depleted Sandstone Formation with Single-Stage Acid in a Vietnam Offshore Case Study
Authors: Ao Taliwati , Thang Pham Cong , Loc Tran Duc 
Published: January 2016

Abstract
Stimulating offshore sandstone formations with depleted reservoir pressure is a challenge. The conventional practices for sandstone acidizing are to pump pre- and post-flush hydrochloric acid to minimize precipitates from the main hydrofluoric acid reacting with the carbonates, and to flow back the well immediately after the acid is pumped. However, in offshore wells, limited deck space for chemical mixing equipment and depleted reservoir conditions necessitated a retarded single-stage HCl/HF acidizing approach with nitrogen.
Because cores were not available, solubility testing was performed using cutting samples with normal HCl/HF acid and retarded single-stage HCl/HF acid. The retarded single-stage HCl/HF acid outperformed the conventional HCl/HF acid in these tests. Because of the challenge in treating long perforated intervals with various permeability zones and depleted reservoir conditions, the operator chose to pump retarded single-stage HCl/HF acid with nitrogen as a diverting and lifting agent. The retarded single-stage HCl/HF acid system eliminated the requirement of pre- and post-flush HCl acid stages, reducing the treatment complexity and overall treatment time.
The successful single-stage HCl/HF acid treatment resulted in a 225% increase in oil production and a 416% decrease in water cut. The decreased drawdown around the wellbore helped improve the oil-water ratio and deliver a lower water cut.
This paper summarizes the challenges of testing, designing and pumping the single-stage sandstone acid system in one well offshore Vietnam.
Novel Evaluation Method of Surfactant and Clay Inhibitor Performance on Fracturing Fluid Recovery for Eagle Ford and Mancos Outcrop Shale Cores using NMR Technique
Authors: Kim Jihye , Gomaa Ahmed M. , Zhang Hao , Nelson Scott G. 
Published: January 2016

Abstract
Because of the unique characteristics of shale formations including low permeability, existence of micro-fractures, and sensitivity to the contact fluids, it is difficult to evaluate the complex microscopic interactions between fracturing fluids and the formation in a traditional laboratory setting. Prior work (SPE 174186) demonstrated the value of using Nuclear Magnetic Resonance (NMR) to evaluate the interaction between shale formations and fracturing fluid components, such as clay control agents and surfactants. The subsequent work (SPE 179122) expanded the research to study more fluids and better understand why the performance of surfactants and clay inhibitors vary with the focus on the Barnett and Marcellus outcrop shale sample. The current work builds on the prior studies with further analyses focused on the high economic value shale play of Eagle Ford and Mancos shale sample.
Outcrop cores from the Eagle Ford and Mancos shales were evaluated in this study. Cores were submerged in various fracturing fluids under different experimental conditions: pressure of 400 psi, temperatures from 150 to 250 °F, and fluid contact times from 2 to 16 days. The change in the fluid volume in the cores during saturation and simulated flowback recovery process was quantified using NMR as a function of the T2 or relative pore radius. In this way, the amount of fluid recovered with different fracturing fluid additives were collected and compared to give formation-specific fluid recommendation based on the relative performance observed with the additives for fluid recovery.
Due to the variations of mineral composition and reservoir properties in different shale formations, the selection of fluid additives used in the fracturing fluids can be optimized based on the characteristics of each shale reservoir. For example, for the Eagle Ford outcrop shale cores with low clay content, any type of clay inhibitors tested in this study showed no sign of clay damage giving similar performance in flowback recovery. In contrast, the Mancos outcrop shale cores with moderate swelling clay content showed higher flowback recovery when treated with permanent clay inhibitor than temporary clay inhibitors.
This work extends understanding of fracturing fluid additives and shale interaction that, in many cases, are currently selected solely based on minimal testing and experience gained from conventional formations, rather than demonstrated performance in a particular shale formation. Moreover, this work opens an opportunity to customize fracturing fluids and services for enhanced fluid recovery by evaluating actual reservoir core from the given area of interest.
Engineering Hydraulic Fracturing Chemical Treatment to Minimize Water Blocks: A Simulated Reservoir-on-a-Chip Approach
Authors: Kim Jihye , Gomaa Ahmed M. , Nelson Scott G. , Hudson Harold G. 
Published: January 2016

Abstract
Fracturing fluid trapping is one of the major sources of damage after well stimulation as the remaining fluids in the pore space reduce the effective hydrocarbon permeability. Especially in tight formations, fluid trapping can require significant time to clean up, even at a high production rate. Outcrop cores have traditionally been used to confirm the existence of damage and to quantify it. However, it is difficult to clearly discern the trapping mechanism in cores and to accurately determine the trapping location and the volume of residual fluid.
In this study, a reservoir-on-a-chip approach was adapted to visualize the residual water blocking process of fracturing fluids. The major advances in using this approach are the clear visualization of the trapping process in the pore space and the control of testing parameters including formation wettability, reservoir/stimulation fluid properties, flow rate, and reservoir pore-space geometry. This study includes two sections: A fluid mechanical study to determine which reservoir conditions require chemical treatments to mitigate water blocks; and a chemical evaluation study to determine how well chemicals, such as surfactants, can alleviate severe water block conditions.
Experimental results confirm that the geometry of the pore throat plays a critical role in trapping and releasing fluid. Furthermore, displacing reservoir fluid at high rates, or with a higher oil viscosity, increases cleanup efficiency. With this fundamental understanding, the reservoir conditions that require chemical treatment can be identified. Cleanup efficiency was significantly improved by using a surfactant. The designs of engineered chemical treatments to mitigate water blocks under specific conditions will be discussed in this paper. These new findings expand the industry’s understanding of the fluid mechanics behind residual fluid trapping, capillary effects, and the implications for engineered fracturing fluid systems.
Theoretical and Experimental Study on Optimal Injection Rates in Carbonate Acidizing
Authors: Dong K. , Zhu D. , Hill A. D. 
Published: January 2016

Abstract
Optimal acid injection rate is critical information for carbonate matrix acidizing design. This rate is currently obtained through fitting acidizing coreflood experimental results. A model is needed to predict optimal acid injection rates for various reservoir conditions.
A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when the pore growth follows a particular mechanism, which is discussed in this paper. We have developed a model to predict wormhole growth behavior. The model uses the mode size in a pore size distribution - the pore size that appears most frequently in the distribution, to predict the growth of the pore. By controlling the acid velocity inside of it, we can make this particular pore grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. With the introduction of a porous medium model, the acid velocity in the mode-size pore is upscaled to the interstitial velocity at the wormhole tip. This interstitial velocity at the wormhole tip controls the wormhole propagation. The optimal acid injection rates are then calculated based on semi-empirical flow correlations for different flow geometries.
The optimal injection rate depends on the rock lithology, acid concentration, temperature, and rock pore size distribution. All of these factors are accounted for in this model. The model can predict the optimal rates of acidizing coreflood experiments correctly, as compared with our acidizing coreflood experimental results. In addition, based on our model, it is also found that at optimal conditions, the wormhole propagation velocity is linearly proportional to the acid diffusion coefficient for a diffusion limited reaction. This is proven both experimentally and theoretically in this study. Since there is no flow geometry constraint while developing this model, it can be applied to field scales. Applications are presented in this paper.
Laboratory Simulation and Damage in Open Hole Water Injectors
Authors: Byrne Michael , Kandasamy Ram , Bruce Angela 
Published: January 2016

Abstract
Completion design in water injection wells has received a lot of attention in recent years. With increasing deployment of sand control and the desire not to fracture with water injection, a much greater emphasis needs to be placed on selection of the optimum drilling, completion and clean-up fluids sequence compliant with the completion hardware.
One tool available to help with the selection process for fluids for drilling and completion is laboratory simulation testing. If performed properly and with attention to the detail required to simulate fluids and hardware, these tests can be employed to predict and optimise well performance.
Taking different examples from different field developments we demonstrate the process of test design and propose some interesting amendments for future test designs. We cite some examples of low or no flow in the laboratory and discuss the implications for real well design and geometry. We also challenge some long held assumptions on the "best" fluids to use for open hole water injection wells.
The paper adds to industry knowledge on this topic and to the development of more representative and revealing laboratory tests. Using real examples from well planning and the subsequent well performance we illustrate the importance of using available tools to help in the design of wells.
Sand Retention Testing: Reservoir Sand or Simulated Sand - Does it Matter?
Authors: Ballard Tracey , Beare Steve , Wigg Nicola 
Published: January 2016

Abstract
Sand retention testing obviously requires sand, and using the reservoir sand is the most straightforward option. However, sometimes reservoir sand is not available in sufficient quantity, and in these instances a particle size distribution matching the reservoir sand is prepared from commercial outcrop sand. The authors were aware that there can be some differences between the results from outcrop and reservoir sands and generally only use reservoir sands, but a recent request for tests using simulated sands gave the impetus for a systematic study of the variations.
Retention tests have been performed with different reservoir sands and two versions of their respective simulated sands; one matched to their laser particle size distribution and one matched to the sieve analysis distribution. Sandpack tests and two slurry test methods (xanthan and caesium formate) have been performed with a range of wire wrap and metal mesh screens. There are quite striking differences in the pressure data recorded between the actual reservoir sands and the simulated sands. The trend in the amount of sand produced between reservoir and simulated sand is still uncertain, but the study has shown some instances that could change the screen recommendations. Efforts have been made to understand the differences between reservoir and simulated sands by examining particle shape.
The results of this study show that using sands simulated from outcrop rock can give retention test results different from those obtained with reservoir sands. This and other potential test artefacts should hopefully discourage reading too much into retention test data; especially for estimating likely sand production. Predictions of sand screen performance based on lab studies will remain problematic until comparisons with field performance (both failures and successes) can be made.
Choke Management Strategies for Hydraulically Fractured Wells and Frac–Pack Completions in Vertical Wells
Authors: Karantinos Emmanouil , Sharma Mukul M. , Ayoub Joseph A. , Parlar Mehmet , Chanpura Rajesh A. 
Published: January 2016

Abstract
When a well is brought on production, the selection of an optimum choke management strategy is aimed towards maximizing well productivity and minimizing the risk of typical wellbore failures during the early life of a well. In this study, a quantitative method is presented for the selection of a choke management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. For example, in unconventional resources, an improper choke management strategy may trigger the back flow of excessive amounts of proppant, resulting in fracture closure and possible wellbore damage and loss of production. In frac-packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage resulting in impaired production and possibly sand production, requiring excessive and costly workovers.
It is shown that in hydraulically fractured wells, choke management strategies should aim towards minimizing pressure gradients along the fracture, thus making proppant flowback and potential reduction/loss of fracture conductivity or its connectivity to the wellbore less likely to occur, for a given set of formation properties and closure stress. Choke management strategies are compared for a wide range of formation and fracture properties including fluid properties, matrix permeability, fracture conductivity and fracture length. Results indicate that in unconventional formations (k&lt;0.01md) there is a unique choke management strategy, which consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed.
In frac-packs and high-rate water packs, completion failure may occur due to excessive fluid velocities along the frac-pack or exaggerated pore pressure gradients at the completion sandface. Choke management strategies are compared for a wide range of formation and completion properties. Results indicate that in frac-packs and high-rate water packs, the selection of the optimum choke management strategy is similar to that of open-hole completions, with bean-up operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering bean-up operations during completion design.
The results of this study provide, for the first time, a clear methodology for selecting choke management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties.
Stability Determination of Acid Emulsions by Droplet Size Characterization With Static Light Scattering
Authors: Weissenberger Markus C. , Khalafpour Peyman 
Published: January 2016

Abstract
Acid emulsions as aqueous acid in oil emulsions are used widely as either acid delayed systems or to clean up formation damages. The stability of emulsified acid blends at room and elevated temperatures is a crucial factor for a successful job execution. To predict the stability and reactivity so far mainly indirect methods, such as visual inspections or conductivity measurements, are used in the industry. These methods are often inaccurate and subjective. They can also lead to a wrong interpretation of acid emulsion stabilities, especially at elevated temperatures. In this study we are presenting a new method of stability determination of acid emulsions by the detection of the droplet size through static light scattering. Static light scattering (or laser diffraction) is a widely used particle sizing technique for materials ranging from several nanometers up to several millimeters in size. This is the typical size range of emulsions. The technique by itself is well-established, allows rapid measurements, and does not need an external calibration. By using this method, we were able to correlate the droplet size of acid emulsions with their stability and to study the influence of different parameters such as solvent, surfactants or temperature. Only the change of the solvent (e.g., from xylene to diesel) can have a tremendous influence on the stability of a 28% hydrochloric acid emulsion. The study of acid emulsions was executed with different solvents, surfactants, acid strengths, and temperatures. Through the direct determination of the acid emulsion stability by measurement of the droplet size, we are able to predict the emulsion stability at elevated temperatures very accurately. This method is also suitable for such emulsions that possess remarkably high acid strengths.
Enhanced Oil Recovery Using Innovative Asphaltene Inhibitors in East Venezuela
Authors: Villard Y. , Fajardo F. , Milne A. 
Published: January 2016

Abstract
Use of adsorption asphaltene inhibitors in mature oil fields in eastern Venezuela has reduced operating costs and deferred production. As is common in mature fields, some fields in the northern district of Monagas state, Venezuela, such as Furrial, Musipan, and Boquerón fields, have had increasing problems of asphaltene deposition for a number of years. Asphaltenes present in a crude oil under normal reservoir conditions will start to flocculate and precipitate in the critical near-wellbore matrix as the reservoir pressure drops, which greatly reduces the productivity of the reservoir. Conventional asphaltene treatment is a two-step process that involves removal of the deposits by pumping solvents and asphaltene dispersants into the formation using coiled tubing. The frequency of the treatments increases as the reservoir pressure drops, and, in some fields, it is common for wells to be treated every 30 days or less, resulting in deferred production and increased costs. Conventional asphaltene inhibitors precipitate in the pore spaces in the matrix of a formation and then slowly dissolve in the produced crude, preventing the flocculation of the asphaltene present in the crude. In contrast, the new generation of asphaltene inhibitors adsorb onto the surfaces of the pore spaces in sandstones or onto the fracture faces in carbonates, providing protection from asphaltene deposition in the formation, tubing, and flowlines over an extended period of time.
These adsorption asphaltene inhibitors were first used in Venezuela to treat wells in the Boquerón field that historically had been treated every 60 days to maintain production. Wells treated with adsorption asphaltene inhibitors maintained their production for over 180 days, greatly reducing both operating costs and deferred production. Results from laboratory tests on the adsorption inhibitors, field operations experience, and lessons from treatment evaluations were incorporated into a workflow that enables optimizing asphaltene inhibition for new fields.
The use of the adsorption inhibitors has reduced the logistics and time required to place these inhibitors in the formation and has greatly decreased the frequency of the treatments needed to maintain the overall production. The initial success of these treatments has led to additional asphaltene inhibition campaigns in other fields.
Comprehensive Field-Scale Injection Performance Analysis Associated with Injected Water Quality Parameters
Authors: Sabut Bangkong A. , Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Zahrani Rashad M. , Nasr-El-Din Hisham A. 
Published: January 2016

Abstract
This paper presents a comprehensive injection performance analysis conducted in major carbonate fields in Saudi Arabia. The production from the fields under study is pressure-maintained by peripheral water injection. More than 190 case studies were examined to generate populated trends and draw relevant conclusions on parameters affecting injection performances. Petroleum engineering concepts/tools, such as pressure transient analysis, were heavily used in this work to establish the effective yearly injection decline rate for each well.
Extensive and dedicated sampling of injected water was carried out as part of water quality monitoring to ensure that well plugging and internal corrosion was minimized. The total dissolved solids, total suspended solids, particle count and size distribution, acidity, iron count, sulfide content, and bacterial growth data were measured and synchronized with the respective wells' injectivity indices to identify potential sources of well injection impairments. Major events, such as when starting or switching the water injection system, were thoroughly factored into the water quality analysis and its subsequent effect on the injection performances.
The well injection performance analysis was carried out using pressure-transient analysis data obtained from Fall-Off Test (FOT) surveys, where each well has a baseline II survey taken when the well was first drilled and completed. Dimensionless injectivity indices were defined to compute the injection potential of each well. Baseline surveys were then compared with the subsequent or the latest surveys, if any, based on which time-lapse measurement trends were generated and analyzed.
Several key findings and recommendations, regarding setting appropriate limits to water quality parameters and injection surveillance strategy, are presented in light of the performed analysis.
This paper also discusses production engineering efforts to mitigate the decline in well injectivity, including: water quality control, well stimulation initiatives to enhance injectivity, and analysis of well plugging characteristics/profiles and their relation to reservoir permeability.