bluuebunny/crossref_metadata_2025_split huggingface dataset:
Isothermal Titration Calorimetry: A New Tool for the Development of Structure Activity Relationships for Sulphide Scale Control
Authors: Ackermann L.-M. , Klapper M. , Kayser C. , Kaiser A. 
Published: March 2017

Abstract
Smart scale management techniques are of great demand in nowadays oil and gas industry. The formation of zinc, iron and lead sulphide scales can cause severe damages of production equipment which ultimately results in loss of productivity.1-4 Currently used materials act inefficient, as high amounts of materials are needed, which makes research in this field demanding.5 However, to develop anti-scaling agents, a deeper understanding of the molecular interactions of the typically used polymers is required. To understand the occurring interactions, isothermal titration calorimetry (ITC) is introduced as a new method, which allows for a more rational design of a new material and makes screenings, as the have been done in the past, unnecessary. With the use of ITC it was proven, that several sulfonic acid, phosphonic acid and carboxylic acid carrying monomers are suitable candidates showing strong interaction with the zinc sulfide surface, which is one of the exotic problems in scale formation.6 Furthermore, the influence of the molecular weight and the composition was identified during the investigations of the different homopolymers and copolymers of the previously tested monomers.
Which Cations are Detrimental to Shale Preservation?
Authors: Recio Antonio , Benoit Denise , Henkel Kristina , York Kevin 
Published: March 2017

Abstract
The water-sensitive nature of shale is traditionally thought to be a factor of the clay content of the rock. Because current practices to mitigate formation damage entail the use of brines to control the osmotic potential of stimulation fluids, we posited that not all brines will induce the same response from Bentonite, Illite, and more importantly shale.
Current industrial practices to mitigate permeability damage in source rock shale reservoirs typically entail the use of sodium-, potassium-, calcium-, tetramethyl ammonium-, and/or choline chloride salt brines to control the rate of cation exchange between formation clays and stimulation fluids. Industrial and literature precedent suggests that below a critical salt concentration (CSC) osmostically-driven cation-exchange between injected fluid and the formation is the primary damage mechanisms for both swelling and migrating clays; however, above the CSC, the potential still exists for crystalline swelling and mechanical destabilization. Examining various clays and clay laden formation materials revealed that certain cations, even above their CSC, will induce formation damage.
To accurately assess the effect and permanency of various brines when introduced to pure clay as well as shales, a statistically relevant laboratory protocol has been developed to evaluate the role differing cations play in shale preservation. The clay and formation cuttings were evaluated for swelling and mechanical stability, then subjected to dynamic experiments using sandpack, coreflow, and API conductivity testing methods. The evaluated formation materials were diagnosed with computed tomography (CT), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy to diagnose permeability damage mechanisms for given treatment fluids and formation material composition.
This paper seeks to advance the existing understanding of the damage mechanisms involved when brine containing stimulation fluids are introduced to shale reservoirs. Currently, there is a lack of consensus on the significance of the identity of the ideal salt-cation treatment to preserve permeability in shale reservoirs. The authors have probed the effect various brines have on clay and unconventional material, which compliments the current body of literature related to shale inhibition.
Short Term Gas Migration Control in Well Cementing: Comparative Behavior of Fluid Loss Control Polymers
Authors: Cadix A. , Thant K. , Neufeld J. , Nelson T. , Auneau L. , Phan C. , Wilson J. 
Published: March 2017

Abstract
Short term gas migration control is one of most critical aspects of zonal isolation that must be achieved through the cementing of a well. It has long been discussed and demonstrated that gas migration occurring either immediately at the placement or in the short-term (e.g. within few hours after plug bump) is a combination of many factors including cement design and density matching. In addition, it is generally considered that fluid loss control additives can play a significant role in the ability of a cement sheath to be considered as gas tight. It is of course mandatory to obtain low fluid loss values to hold cement initial design with adapted density, water content for full cement hydration and effective placement but even with identical fluid loss and rheology, very different gas permeability results can be obtained with different types of fluid loss control additives.
This study is focused on the investigation of the relative performance of several fluid loss polymers and their ability to form a gas tight sheath. Systems that were considered for the study were conventional additives based on high molecular weight water soluble polymers such as so called "AMPS" based anionic copolymers and styrene butadiene latex which were compared to a newly developed block copolymer. This latter comprises first a strong adsorbing block, then a long second hydrophilic block providing filtration control. This technology was already demonstrated to be very effective in preventing performance losses in the presence of competitive formulation additives such as dispersant or retarders (see SPE173758). In addition in this work gas permeation through setting cement sheath was investigated and a systematic study on permeability and porosity within filter cake and setting cement using Mercury Intrusion Porosimetry (MIP) was carried out. MIP results were discussed versus direct scanning electron micrograph imaging.
As expected, it was confirmed that low fluid loss is mandatory to successfully pass a gas migration test. In addition, it was shown that in spite of comparable standard fluid loss control performance, actual permeability and porosity reduction within the filter cake can be significantly different. As far as pore sizes within the setting cement are concerned, there was here very limited impact of the fluid loss additive system. It was confirmed as expected from industry standards that styrene butadiene latex very effectively reduce permeability but diblock copolymer can to a fair extent be considered as a very effective substitute to design gas tight slurries.
Squeezing the Bakken: Successful Scale Squeeze Programs Lead to Shift in Bakken Scale Control
Authors: Spicka K. J. , Eagle L. Holding , Littlehales I. , Fidoe J. , Jordan M. M. , Zosel Z. , Glasser S. 
Published: March 2017

Abstract
This paper highlights efforts taken in answering the following question: "Can horizontal unconventional shale wells be successfully squeezed for scale control?".
The Bakken shale formations in North Dakota, Montana and Alberta have presented unique operational challenges during the unconventional play boom. Despite the ability to control scale formation with conventional scale inhibitors under Bakken conditions, scale formation (primarily calcium carbonate) can still remain an operational challenge due to well design and sub-optimal scale inhibitor deployment.
Due to limited experience in the industry in scale squeezing fractured long reach horizontal wells, scale squeezes have not been frequently applied in the Bakken. As a result of sub-optimal scale control despite application of suitable scale inhibitors, an in-depth evaluation of scale squeeze chemistries, application methods and scale squeeze modeling has been ongoing in the Bakken. These successful applications are being studied to improve current scale squeeze modeling approaches for horizontal, fracked wells in addition to understanding the factors that impact Bakken scale squeezes. The lessons learned in modeling, application and monitoring of the scale squeezes will be discussed in this paper. Squeeze9 and Place-iT™ field history matching indicate the primary impact to squeeze life is the amount of scale inhibitor (both concentration and volume) used while overflush volumes have less of an impact. This varies from traditional scale squeezes that combine scale inhibitor and overflush volumes to achieve the desired scale squeeze lifetime. Due to the unique brine chemistry of the Bakken, squeeze monitoring has relied less upon traditional ion tracking and almost exclusively upon more advanced environmental scanning electron microscopy (ESEM) of suspended solids within the produced brine samples. Examples of successful Bakken squeezes lasting more than 1 year will be highlighted.
The successful applications of scale squeezes in the Bakken are bringing a new method of efficient, cost effective, long term scale control to unconventional plays. The lessons learned in the Bakken, and the resulting advancement of unconventional scale squeeze models and theories, have implications for the global industry as unconventional plays across the world are identified, explored and produced.
Low-Interfacial-Tension Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Carbonate Reservoirs
Authors: Dong Pengfei , Puerto Maura , Ma Kun , Mateen Khalid , Ren Guangwei , Bourdarot Gilles , Morel Danielle , Bourrel Maurice , Biswal Sibani Lisa , Hirasaki George 
Published: March 2017

Abstract
Oil recovery in highly heterogeneous carbonate reservoirs is typically inefficient because of the high permeable fracture networks and unfavorable capillary force resulting from oil-wet matrix. Foam as a mobility control agent has been proposed to mitigate reservoir heterogeneity by diverting injected fluids from the highly permeable fractured zones into the low permeable unswept rock matrix, hence improving the sweep efficiency. This paper presents the use of a low-interfacial-tension foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. The novel formulation providesboth mobility control and oil-water interfacial tension (IFT) reduction to overcome the unfavorable capillary forces preventingdisplacing fluids from entering oil-filled matrix. Thus, as expected, the combination of these two effects significantly improves oil recovery compared to either foam or surfactant flooding.
In this research, the three-component surfactant formulation was tailored by phase behavior tests in seawater with crude oil from a targeted reservoir. The optimized formulation can simultaneously generate 10−2 mN/m IFT and strong foam in porous media with oil present, as demonstrated by IFT measurements and foam floodingtests. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting core lengthwise and precisely controlled of aperture by applying specific confining pressure. The foam flooding experiments reveal that the low-IFT foaming formulation in an oil-wet fractured Edward Brown dolomite recovers about 72% of oil while water flooding only recovers less than 2%,and it is more efficient than foam flooding lacking low oil-water IFT property.The core flood test results also indicate that low-IFT foam diverts mostly surfactant solution into matrix because of (1) the mobility reduction due to foam in the fracture network, (2) significantly lower capillary entry pressure for surfactant solution compared to gas and (3) the increase of mobility to water in the matrix by the low oil-water IFT displacing residual oil in the matrix. This selective diversion effect of the novel foaming system allows to carry out the surfactant flooding at low IFT condition in the low permeability matrix to recover the trapped oil, which is otherwise impossible with simple surfactant or high-IFT foam flooding in highly heterogeneous or fractured reservoirs.
Polyethylene Glycol PEG Functionalized Silane for Highly Efficient Silicate Scale Control
Authors: Meng Fei , Aften Carl 
Published: March 2017

Abstract
Sandstone reservoirs flooded with alkaline surfactant polymer (ASP) are associated with silicate scaling of production wells. Silicate scaling has been a significant problem in ASP-flooded areas in China and Canada. This paper reports a series of highly effective silicate scale inhibitors comprised of polyethylene-glycol-functionalized silane.
Surface chemistry of silicate was utilized to prevent scale growth. Silane/siloxide groups bond well with the surface of silica and silicates. The introduction of a silane/siloxide group into a scale inhibitor can greatly enhance the affinity of inhibitor molecules with the silicate surface. Conversely a silicate surface also has exposed OH groups which can form hydrogen bonds with the oxygen atoms in the backbone of PEG. The PEG polymer chain is likely to wrap around the surface of silicate nuclei, thus becoming a blocking layer and inhibiting further silicate growth.
Both static and dynamic tests were utilized to evaluate the performance of the silicate scale inhibitors. The PEG-functionalized silane achieved excellent inhibition percentages at low or medium pH as compared with conventional inhibitors that are based on phosphonates or polycarboxylic acids. When brine solution pH is high, magnesium (Mg) and calcium (Ca) silicate form, grow larger, and precipitate out, before effective inhibition can occur. This research found the addition of Mg/Ca sequesters help mitigate this growth/precipitation problem by slowing the initial nucleation process.
This novel study supports the introduction of a silane/siloxide group that specifically binds the inhibitor with silicate nuclei providing the advantages over conventional technologies where no specific binding between an inhibitor and precipitate is established.
Characterization of Filter Cake Generated by Nanoparticle-Based Drilling Fluid for HP/HT Applications
Authors: Mahmoud Omar , Nasr-El-Din Hisham A. , Vryzas Zisis , Kelessidis Vassilios C. 
Published: March 2017

Abstract
As high-pressure/high-temperature (HP/HT) drilling is inherently expensive, drilling fluids and technologies should be carefully selected to successfully handle the associated challenges. Over the past few years, nanoparticles (NPs), among other additives, have been investigated to address these challenges. The objective of this study is to investigate the potential of using ferric oxide NPs on the filter cake properties in downhle drilling environments.
Having an efficient filter cake is an important property of the drilling fluid and can affect the success of drilling operations. This research focuses oncharacterizatingthe filter cakes produced by Ca-bentonite-based drilling fluid contains ferric oxide NPs at downhle conditions. A combination of computed-tomography (CT) scan and scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS) was used in filter cake characterization. The effect of NP concentration, fluid preparation method, and filtration condition were studied. A HP/HT filter press was used to perform the filtration process at conditions up to 350°F and 500 psi. Indiana limestone core disks were used to simulate the filter media.
The experimental results showed that the ferric oxide NPs improve the filter cake and filtration properties of Ca-bentonite-based drilling fluid in the presence of polymer and other additives. Low NP concentration is preferred for obtaining a good cake quality with the best characteristics obtained at 0.3–0.5 wt% NPs. Furthermore, this drilling fluid can withstand conditions up to 500 psi and 350°F. Cake properties of 0.151 in. thickness, 6.9 ml filtrate volume, and 0.428 µd permeability was obtained at such conditions. The addition of NPs to the drilling fluid improved the filter cake properties under both static and dynamic filtration. SEM-EDS analysis confirmed the efficiency of using NPs to form a smoother/less porous filter cake morphology. Moreover, sonication for one hour and hydration for 16 hours are recommendedfor better preparation of these fluids.
This research provides an experimental evaluation of using ferric oxide NPs with Ca-bentonite-based drilling fluid to produce high-quality filter cake at downhole conditions. The characteristics of the filter cake gererated confirmed the efficiency of such fluids.
Hydrophobically Associating Polymer Water-in-Oil Emulsions Used in Multi-pad Fracking for Tight Oil Reservoir: The First Example in China
Authors: Lv Yongli , Feng Yujun , Wang Zenglin , Li Aishan , Zhang Quansheng , Huang Bo , Zuo Jiaqiang , Ren Zhanchun , Chen Yong 
Published: March 2017

Abstract
Multi-pad hydraulic fracturing is believed a cost-effective procedure to unlock the tight oil from low-porosity, low-permeability reservoirs. However, the inconvenience of difficult-dissolving process at surface and crosslinking of the conventional guar-based fracturing fluid systems cannot satisfy such fracking jobs because of the massive proppant loading, high flow rate and large volume of the fluids used.
To address these issues, a crosslinking-free and rapid-dissolution fracturing fluid system based on synthetic hydrophobically associating polymer (HAP) "water-in-oil" emulsion was developed. The HAPs are derived from classical water-soluble polymers by incorporating small amount of long hydrophobic side chains onto the polymer backbone. When above a critical associating concentration, these polymers can automatically form a three-dimensional transient network by intermolecular association, reminiscent of cross-linked structures, offering the suspending capacity for proppants. With inverse emulsion polymerization, the obtained HAP emulsions can not only get high molecular weight, but also be rapidly dispersed and finally dissolved within 5 minutes.
It was found concentrated HAP polymer emulsions can be dispersed online with surface water or even produced fluids to get final designed concentration. Laboratory rheological study shows that 1% of the as-prepared fracturing fluid can reach more than 50 mPa%s at 150 0C. Compared with guar-based fluid, the HAP fracturing fluid can be completely broken, and the viscosity, surface tension, skin damage of the residual fluid on the permeability are all smaller, while the fluid loss is comparable, proppant-carrying ability is even better. Most importantly, no further surfactant was needed to assist the flowback the fluid.
Since September 2013, such associative polymer fracturing fluids were successively used in 29 wells of 3 well pads, Yan-227, Yan-22 and Bin-37 blocks in Shengli Oilfield, Sinopec, where the temperature ranges from 110 to 145 cC. Totally 60,000 m3 fluids were consumed in these fracking jobs, and 87, 9, and 45 stages were successively fractured in the horizontal sections, respectively.
A New Application of Potassium Nitrate as an Environmentally Friendly Clay Stabilizer in Water-Based Drilling Fluids
Authors: Zhou J. , Nasr-El-Din H. A. 
Published: March 2017

Abstract
Currently, the application of potassium chloride (KCl) as a temporary clay stabilizing additive in water-based drilling fluids is challenging in chloride-sensitive formations due to problems with wellbore stability and drilling fluid. Its use can also impose significant additional costs to drilling operations. In addition, the chloride ions can cause contamination, with the potential to inhibit the growth of vegetation and to pollute aquifers. The purpose of this study is to propose a new high-performance water-based fluid system using potassium nitrate (KNO3) instead of potassium chloride as a clay-stabilizing additive for drilling applications.
Water-based drilling fluids using potassium nitrate and potassium chloride, respectively, were prepared with a density of 1.3 S.G. using API barite (BaSO4, D50=15-20 μm, S.G.=4.2), manganese tetraoxide (Mn3O4, D50=1 μm, S.G.=4.8), or micronized ilmenite (FeTiO3, D50=5 μm, S.G.=4.5-4.7) as weighting materials. The Capillary Suction Time (CST) test was used to optimize the brine concentration in drilling fluids for effective clay swelling inhibition. High-pressure/high-temperature (HP/HT) filtration tests were conducted under static conditions at 250°F and 300 psi. Berea sandstone cores with an average porosity of 23 vol% and an average permeability of 100 md were used in the filtration tests. The rheological properties, the volume of filtrate and the filter cake thickness generated by the water-based drilling fluids were determined and compared.
CST results show that potassium nitrate exhibits characteristics similar to potassium chloride as a clay stabilizer above 4 wt% concentration. The water-based drilling fluid containing potassium nitrate has very similar rheological properties when compared with potassium chloride. The HP/HT filtration press results show that water-based drilling fluid with potassium nitrate has a low filtration volume, less than 1 cm3, and formed thinner filter cake when using API barite as the weighting material. This paper not only highlights the successful replacement of KCl by KNO3 to achieve good rheological properties in water-based drilling fluids, but also shows that KNO3-based drilling fluids are more environmentally friendly than KCl-based drilling fluids.
Effective Removal of Hydrogen Sulfide and Mercaptans in Oilfield Applications
Authors: Chakraborty Soma , Lehrer Scott , Ramachandran Sunder 
Published: March 2017

Abstract
Sulfur contaminants in the form of hydrogen sulfide and mercaptans are undesirable for various reasons during sour crude production. For example, hydrogen sulfide and mercaptans can be hazardous to personnel. Their presence can create major corrosion issues pertaining to the assets. Furthermore, these components can be objectionable because of their chemical reaction with other hydrocarbons or fuel system components. In addition to the risk of direct harm to exposed personnel, products and equipment, environmental considerations such as odor and emission control must also be addressed. Increasing urbanization is moving more and more housing developments within the affected zone of many facilities. Depending on local and national regulations, penalties and fines can result from exceeding either hydrogen sulfide or mercaptan emissions standards.
There are several chemistries available for treating hydrocarbon feeds containing sulfur compounds and acidic components like hydrogen sulfide and mercaptans. The early processes included treatment of the hydrocarbon fractions with caustic, clays and hydro-treating as well as the UOP Merox™ process. One disadvantage of caustic treatment is that disposal of spent caustic is undesirable for environmental reasons. One of the most popular methods of treatment comprises scrubbing with mono or diethanolamine in a regenerative amine system. Amine systems, however, cannot sufficiently remove mercaptans. Although several chemistries are effective in scavenging hydrogen sulfide, there is a need for chemistries effective for scavenging mercaptans, especially in the presence of hydrogen sulfide.
The paper presents new chemistries that scavenge hydrogen sulfide and simultaneously scavange mercaptans extremely efficiently. A lab technique is also presented that was designed to mimic a field gas-tower application. A new analytical technique is described that simultaneously detects hydrogen sulfide and mercaptans. The gas concentrations are detected before and after scavenging. A systematic performance evaluation proves the efficacy of the scavengers in simultaneously scavenging hydrogen sulfide as well as mercaptans.