bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Component Sorbed-Phase Considerations for Shale Gas-in-place Calculations
Authors: Ambrose Ray J. , Hartman Robert C. , Akkutlu I. Yucel 
Published: September 2011

Abstract
Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorbed-gas by not properly accounting for the volumes occupied by the sorbed and free gas phases. Scanning electron microscopy (SEM) has discovered nanopores in organic-rich shale with sizes typically in 3-100 nm range, although pores less than 3 nm cannot be captured with current SEM technology. At that scale the adsorption layer thickness is not infinitesimally small. Thus a portion of the total pore volume would be occupied by a finite-size adsorption layer and not available for the free gas molecules. In SPE 131772, we proposed a volumetric method which accounts for the volumes taken up by the free gas and by the adsorption layer. The study was based on a single-component Langmuir adsorption model, however. This paper extends the discussions on the adsorption layer effect for multi-component natural gases with a sorption model also known as extended-Langmuir.
We combine the extended-Langmuir adsorption isotherm with volumetrics and free gas composition to formulate a new gasin-place equation accounting for the pore space taken up by a multi-component sorbed phase. The method yields total gas-inplace predictions, which suggest that an adjustment is necessary in volume calculations, especially for gas shales with high C2+ composition and high in total organic content. Using typical values for the parameters, calculations show a 20% decrease in total gas storage capacity compared to that using the conventional approach. The adjustments need to be done on the free gas volume is 18% more than the value using single-component (methane) case. The role of multi-component adsorption is more important than previously thought. The new methodology is therefore recommended for shale gas-inplace calculations.
Correlating Wettability Alteration with Changes in Eelative Permeability of Gas Condensate Reservoirs
Authors: Gilani S. F. , Sharma M. M. , Torres D. , Ahmadi M. , Pope G. A. , Linnemeyer H. 
Published: September 2011

Abstract
In gas condensate reservoirs, considerable productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluids. Over the years, several methods have been proposed to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods such as gas recycling, hydraulic fracturing and solvent injection have shown to restore the production on a temporary basis only. Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable and permanent solution to this problem. The selection of these treatments from a large pool of potentially effective chemicals requires extensive laboratory testing which requires time and money.
In this paper, we present data that correlates changes in wettability with improvements in relative permeability. Imbibition, contact angle and X-ray photoelectron spectroscopy (XPS) tests along with coreflood results are used to characterize wettability changes. XPS tests, drop tests and core flood experiments were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs.
The method discussed in this paper can be successfully used to identify chemical treatments that can change rock wettability and, therefore, relative permeability. This provides a simple and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers. In this way the number of HTHP core floods needed is minimized which saves time, cost and effort.
Corrosion-Inhibitor Design for Compatibility with Acid-Gelling Polymers
Authors: Cassidy Juanita , Kiser Chad , Smith Chris 
Published: September 2011

Abstract
Polymers used for delayed acid gelling are designed to crosslink with metal crosslinkers once the acid is spent to a certain pH so that the resultant solution-viscosity increase will cause acid diversion. However, some organic molecules have the ability to react with the functional groups of the polymers and cause crosslinking before a pH rise. Consequently, the higher viscosities resulting from early crosslinking can affect the pumpability of the acid blend and can also lessen the ability of the polymer to clean up from the formation following diversion.
Aldehydes, used as active components in many acid corrosion inhibitors, have the potential side effect of prematurely crosslinking polyacrylamide-based acid-gelling agents because of the reaction of the aldehyde with the polymer amide groups. Furthermore, other unsuspected inhibitor active ingredients might also convert to aldehydes in an acidic environment and cause crosslinking problems.
The chemistry of the reaction of different aldehydes with polyacrylamide-based gelling agents is presented through use of analytical techniques, along with viscometer studies that simulate downhole conditions. These investigations consider how the molecular structure of the aldehyde affects crosslinking with temperature and acid strength.
Based on information learned from the study of aldehyde interactions with the polymer-gelling agent, an acid corrosion inhibitor can be designed that does not cause any interference when used in conjunction with acid-gelling polymers. Development of such a corrosion inhibitor is presented.
Surface Energy of North American Shales and its Role in Interaction of Shale with Surfactants and Microemulsions
Authors: Zelenev Andrei S. 
Published: September 2011

Abstract
In recent years a number of laboratory studies on the use of surfactants and microemulsions in hydraulic fracturing of shale formations have been reported. These studies mainly focused on such metrics as improvement in permeability regain and enhancement of fluid recovery from packed columns upon the use of surfactant-containing chemicals. Laboratory studies have also been backed by the documented observations from the field illustrating benefits of using microemulsions for the increase in gas production from shale formations. It is a commonly accepted view that these additives benefit gas production by lowering capillary pressure and altering wetability of shale formation. Although it is recognized that the interaction of surfactants and microemulsions with shale is governed by the energetics of solid/liquid, liquid/gas and solid/gas interfaces, there are practically no studies in which surface energies have been determined for different shales. The surface energy, as well as dispersive, non-dispersive, Lifshitz-van der Waals, and Lewis Acid-Lewis Base components of surface energy of several North American shales have been determined from contact angle measurements. It has been discovered that the surface energy of all shale rocks is rather low, typically in the range of 40-50 mJ/m2 a contribution from non-dispersion ("polar") component of about 8-11 dyn/cm. Consequently, shales are capable of interacting with liquids predominantly via dispersion and Lifshitz-van der Waals molecular interactions, which should substantially influence the orientation of surfactant molecules and microemulsion moieties at the shale surface. Furthermore, there was no significant variation in surface energy of shales from different basins, which suggests that individuality of shale surface chemistry should play only a secondary role in the development of shale-specific chemical treatments, and factors other than surface chemistry should be considered first.
Optimized Stand-Alone Screen Design for the 'J' Field, Malaysia
Authors: Regulacion Rhandy , Seno Andreas , Safiin Norhisham Bn , Zarina Nik , Khansani Suryana Bt 
Published: September 2011

Abstract
Gravel pack and stand-alone screens (SASs) are the two most commonly used sand-control methods for openhole (OH) well completions in unconsolidated formations. When comparing the two methods, gravel pack is considered the more robust for sand control and is expected to have a longer service life than SAS in similar reservoir and operational conditions. However, gravel pack costs more per foot than SAS, which limits its use to poorer-quality sands in projects with acceptable economics. The industry has developed accepted criteria for selecting these sand-control methods, and this documentation provides guidelines as to when SAS should be sufficient and when gravel pack is more appropriate, depending on sand quality, which is based on particle-size distribution (PSD) of formation sand samples.
Unfortunately, many small oilfields with poor quality unconsolidated formations cannot be developed economically using gravel pack. SAS is the next best alternative, and often, the only option to bring those small oilfields online. The ‘J’ Field in Malaysia is an example of a small oilfield with marginal economics that was developed successfully using SAS completions despite the fact that the sand quality called for gravel packing. This paper discusses the methodology used in selection and sizing of the SAS design for the ‘J’ Field.
The methodology involves two major processes: 1) review of PSD information for initial screen micron rating selection, and 2), retention-plugging testing of wire-wrapped screen (WWS) and mesh screens for screen-type selection and screen micron rating optimization. Using this methodology, the operator and service company were able to design a completion strategy for eleven (11) wells that fulfilled the economic needs of the development project while resolving the sand-control needs.
Analytical Assessment of Water-free Production in Oil Wells with Downhole Water Loop for Coning Control
Authors: Jin L. , Wojtanowicz A. K. 
Published: September 2011

Abstract
Typically, in the presence of water coning, a water-free production is economically unattainable since critical rates are too small. Downhole water sink (DWS) technology has been proved and demonstrated as capable of significantly increasing critical rates. In actual practices, however, DWS wells have produced oil above critical rates but with lower water cut that resulted in high oil rates and the need for water separation. In fact, water handling is an inherent downside of DWS since the downhole water drainage (for coning control) involves independent lifting of oil and large amount of water to the surface. In contrast, downhole water loop (DWL) technique would combine coning control with water-free production by recycling the drained water from the water sink (drainage) and source (injection) completions and keeping the water in-situ. Experiments show that the beneficial effect of water recycling on well performance is very strong – a moderate water recycling rate would increase critical oil rate by ten times comparing to the conventional well.
Although attractive, the DWL technique is constrained by well-reservoir system properties such as oil viscosity, relative oil permeability, bottom water thickness, well penetration and reservoir anisotropy. This study offers a simple analytical model describing the effects of the above parameters on the water-free oil production rate. The model has been derived using principles of the flow potential theory and anisotropy transformation supplemented with some empirical correlations. A comparison with reservoir simulator demonstrates time savings and acceptable accuracy of the analytical approach. A sensitivity study reveals factors most critical for using DWL in specific reservoirs: critical thickness of the bottom water, limiting value of the fluids mobility ratio and strong effect of permeability anisotropy in the reservoir and water layer. Also presented is a statistical assessment of reservoir systems potentially suitable for the DWL technique.
Multifunctional Compact Well Maintenance System
Authors: Tait G. , Smith I. 
Published: September 2011

Abstract
Multi Functional Compact Well Maintenance System Provides the Ability to Evaluate, Maintain and Remediate Mature Wells Providing Cost Effective and Efficient Well Servicing.
In order to maximize production and to extend the economic life of their wells, Operators today face a number of challenges in organizing required services while maintaining cost efficiency. This is particularly true for wells on small or satellite platforms where available space is limited and crane capacity is often insufficient for some standard service equipment to be deployed. This can apply to many of the services required such as capillary string deployment for many forms of chemical injection, safety valve retrofit and remediation, Slickline services, surface readout or memory data acquisition and thru tubing installations such as plug setting. In many cases mobilization of a rig often supplies the only viable option, the cost of which can be prohibitive.
To address these issues a new Well Maintenance System (WMS) has been created which incorporates compact modular units each designed to weigh less than 2000lbs which are easily transportable and can be combined in various ways to provide all of the services which may be needed from a single source.
In this paper the authors will discuss the introduction of this versatile and compact multifunctional WMS which has been specifically designed to provide single source high performance, safe and efficient well service operations without the need for costly rig mobilization.
Modeling and Simulation of Nitrate Injection for Reservoir Souring Remediation
Authors: Haghshenas Mehdi , Sepehrnoori Kamy , Bryant Steven L. , Farhadinia Mohammad Ali 
Published: September 2011

Abstract
Reservoir souring refers to the onset of hydrogen sulfide production during waterflooding. Besides health and safety issues, H2S content reduces the value of the produced hydrocarbon. Nitrate injection is an effective method to prevent the formation of H2S. Designing this process requires the modeling of a complicated set of biogeochemical reactions involved in the production of H2S and its inhibition. This paper describes the modeling and simulation of biological reactions associated with the injection of nitrate to inhibit reservoir souring. The model is implemented in a general purpose adaptive reservoir simulator (GPAS). To the best of our knowledge, GPAS is the first field-scale reservoir simulator that models reservoir souring treatment.
The basic mechanism in the biologically mediated generation of H2S is the reaction between sulfate in the injection water and fatty acids in the formation water in the presence of sulfate-reducing bacteria (SRB). There are proposed mechanisms that describe the effect of nitrate injection on souring remediation. Depending on the circumstances, more than one mechanism may occur at the same time. These mechanisms include the inhibitory effect of nitrite on sulfate reduction, the competition between sulfate-reducing bacteria and nitrate-reducing bacteria (NRB), and the stimulation of nitrate-reducing sulfide-oxidizing bacteria (NR-SOB). For each mechanism, we specify the biological species and chemical components involved, and determine the role of each component in the biological reaction. For every biological reaction, a set of ordinary differential equations along with differential equations for the transport of chemical and biological species are solved.
The results of reported experiments in the literature are used to find the input parameters for field-scale simulations. This reservoir simulator can then predict the onset of reservoir souring and the effectiveness of nitrate injection and helps the design of the process. The comprehensive modeling accounts for variation in biological system characteristics and reservoir conditions that affect the production and remediation of hydrogen sulfide.
Polymer Chemistry Improves Productivity in Tight Gas Hydraulic Fracturing
Authors: Hutchins Rick , Daniel Sylvie , Wirajati Agustinus Yudho , Ladva Hemant , Williamson Don 
Published: September 2011

Abstract
An additive consisting of acrylic co-polymers, polyvinyl alcohols, polyvinyl acetates, polyvinyl versatates, butyl maleates, and polyvinyl pyrrolidones is considered as a fracture efficiency modifier (FEM) for inclusion in fracturing fluids for tight gas (0.001 to 0.5 mD). The chemical nature of the fracture efficiency modifier improves fluid efficiency, promotes cleanup, enhances gas production, and increases the effective fracture length. Although conventional thought suggests that fluid efficiency is not a controlling parameter in tight gas treatments, this work suggests it can be critical to enhancing well productivity. Lab studies support the field trends in regards to cleanup and fluid efficiency. A modified method for evaluating fluid loss tests provides more realistic values for wall building coefficient and spurt that can improve fracture simulator predictions and support the use of the fluid efficiency modifier.
The liquid additive is easily implemented in the field. Wells treated with the polymer chemistry have better initial and long-term production, faster cleanup to gas sales, longer effective fracture length and require less pad volume while placing the same amount of proppant. The paper also describes high differential pressure leakoff test results at 7,000 psi to emphasize potential irreversible damage due to fracturing fluid invasion into rock matrix. This condition is more prevalent as treated reservoirs become deeper, especially in active tectonic areas around the globe.
Tight gas wells with permeability from 0.01 to 0.14 mD show one year production improvements up to 41% due to the chemistry of the fracture efficiency modifier polymer included in the fluid. The wells typically were designed with reduced pad volume and production analysis suggests the wells show longer effective fracturing length, higher fluid efficiency and faster cleanup, while placing the same mass of proppant. Tighter wells with permeability of less than 0.005 mD showed higher conductivity with smaller fracture length. These wells showed cost reductions while yielding the same cumulative gas production.
Reservoir Fluid Evaluation and Flow Assurance Analysis: Offshore Field, South East Asia
Authors: Lim Lee Chin , Wa Wee Wei , Haddad Sammy , Tighe Michael 
Published: September 2011

Abstract
Representative fluid samples are essential to achieving high quality PVT and flow assurance lab analyses. This is especially important when downhole samples are acquired in an oil base mud (OBM) environment. These high quality samples are also needed to better understand reservoir and fluid behavior throughout the field life.
This work presents a case study of an offshore field in East Asia that required high quality reservoir oil fluid samples for detailed PVT and flow assurance analyses. An oil bearing sand was discovered during the development drilling phase of a predominantly gas bearing reservoir environment. It was required to take low contamination samples from this zone during the development drilling phase without compromising the primary well objective of completion as a gas producer. As such, samples had to be taken on wireline in an oil based mud (OBM) environment. Accordingly a carefully planned methodology and technology was planned and used to achieve the goal of obtaining reservoir fluid samples.
Samples acquired from a previous well in the field using traditional openhole wireline formation testing technology and methods resulted in relatively high contamination levels. High levels of OBM filtrate contamination typically have detrimental effects on the PVT analyses quality for both gas and oil samples. Rig time, cost and sticking risk also limited the time allowed for the wireline formation tester to stay stationary at a sampling depth. As a result, a decision was made to utilize a new sampling technology, Quicksilver, that is specifically designed to obtain low level contamination samples while minimizing sampling station and hence rig time. To achieve this goal, the job was carefully designed and monitored by operating company and service company experts in real time to ensure the required results. The sampling technology, method and field and laboratory results are presented in this work.
Evaluations to Mitigate Water Coning and Sand Production by Integrating LWD Technology with Completion Designs
Authors: Sharma Aviral , Bryant David , Bieltz Tom , Obvintsev Alex , Riegler Paul , Neuschaefer Russ , Kok Jeffrey , Han Shim Yen 
Published: September 2011

Abstract
Horizontal and multilateral completions have become increasingly popular as operating companies strive to maximize oil production and minimize the number of wells in Gulf of Mexico (GOM) Shelf. Horizontal oil producers are challenged by gas or water coning that can shorten the well life due to variation in wellbore pressure and reservoir properties from toe to heel. Differences in permeability and/or water saturation, undulations in the wellbore and toe to heel frictional pressure drop can all contribute to early gas or water coning. GOM Shelf sands are predominantly un-consolidated and therefore require appropriate drilling BHAs with placement strategies along with suitable sand control to prevent accumulation in the wellbore and/or erosion of down hole completion components and surface facilities. GOM Shelf sands can contain abundant fines and are non-uniform. The particle size distribution often varies with depth and along the wellbore, thereby making sand control a major challenge.
This study descends on an existing GOM Shelf horizontal well that was completed with prepacked screens that sanded in and plugged the well after five years of high water production. A recent reservoir saturation logging run across the reservoir near the toe-end of the lateral granted the viability to revisit this reservoir. Consequently, a new offset horizontal was proposed next to the existing one to sweep out the remaining recoverable reserves. Studies based on existing field data and history match were used to evaluate drilling, well placement, and completion design. Simulations were performed to evaluate attic placement methodology and the inclusion of Inflow Control Devices (ICDs) into the sand control completion and to optimize the integrated design. The results illustrates that attic placement is feasible using azimuthal resistivity measurement with the integration of ICDs to not only delay water coning but also choke back any water that might eventually migrate into the wellbore. Finally, the ICD modeling demonstrates improved sweep efficiency from toe to heel. Both water/gas coning and sand production impose significant risks for lateral well placement and completion design in GOM Shelf especially in horizontal and multilaterals wells. This paper addresses these risks and proposes optimum well placement drilling strategies and completion design to mitigate them.