bluuebunny/crossref_metadata_2025 huggingface dataset:
Our experience in endoscopic management of mucormycosis: a case series and review of literature
Authors: Singh Inderdeep , Gupta Vikas , Gupta Salil Kumar , Goyal Sunil , Kumar Manoj , Singh Anubhav
Published: March 2017

Sinonasal mucormycosis is uncommon entity and it rarely infects a healthy host. When it does occur; it becomes very difficult to treat because of the speed of progress of disease and can have fatal outcomes. The mainstays of therapy are treatment of immunocompromised status, systemic high dose Amphotericin B, and surgical debridement of necrosed or nonviable tissue. The following six cases, managed at our centre from July 2016 to October 2016, outline nuances in the diagnosis of invasive sinonasal mucormycosis and highlight the importance of timely surgical debridement and importance of endoscopic approach in complete clearance of disease in order to facilitate medical management to work. All cases included in this study were found to be immunocompromised and had unilateral severe diminution of vision due to periorbital extension of disease. Diagnostic nasal endoscopy revealed black-brown crust and tenacious pus filling up nasal cavity, erosion of turbinates and nasal septal perforation. One patient showed erosion of hard palate and eschar formation. CECT/MRI of PNS showed evidence of bony erosion and orbital involvement. Biopsy taken during nasal endoscopy confirmed the presence of mucormycosis. All patients were started on Liposomal Amphotericin B and broad spectrum antibiotics in renal corrected dosages and taken up for urgent endonasal endoscopic debridement. All paranasal sinuses were cleared and orbital decompression was done. Postoperatively all patients were continued on Liposomal Amphotericin B in renal corrected dosages for two-three weeks and being followed up monthly. One patient could not survive due to several co morbidities and severe immunocompromised status. Only one patient showed recurrence of disease on one month postoperative follow up. Five patients showed improvement in visual acuity. Sinonasal mucormycosis if inappropriately diagnosed and treated can be a fatal condition. Energetic diagnostic workup, combined with equally energetic management, surgical and management leads to favourable outcome.
 
Case Study: A Two-Part Salt-Tolerant Friction Reducer System Enables the Reuse of Produced Water in Hydraulic Fracturing
Authors: Xu Liang , Lord Paul , He Kai , Riley Howard , Koons Justin , Wauters Todd , Weiman Sam
Published: March 2017

Friction reducers (FRs) are an important component of slickwater hydraulic fracturing applications. Using only a single FR system throughout the entire treatment is highly desired in water sources of salinity varying up to 300,000 ppm. This paper discusses field trials of a new salt-tolerant FR system in the Marcellus shale.

A three-well trial program was initiated in the Marcellus. Multiple water sources with varying salinities were used with up to 100% reuse of produced water. The new FR system enabled the pumping pressure to be reduced below 8,500 psi, and the pumping rates were increased and maintained at approximately 100 bbl/min.

This new salt-tolerant FR system consists of a water-in-oil cationic polymer and a surfactant inverter. Unlike other FRs, the distinctive advantage of this FR is that the ratio between polymer and inverter can be readily adjusted on-the-fly to achieve maximum friction reduction.
Zinc and Lead Interactions in Combined Sulphide Scales
Authors: Al-Harbi B. G. , Graham A. J. , Sorbie K. S.
Published: March 2017

Zinc sulphide (ZnS) and lead sulphide (PbS) have both been observed as mineral scale deposits in high-temperature high-pressure HT/HP oil and gas fields. ZnS and PbS deposition can pose safety hazards and have serious economic consequences. Some field results have revealed the formation of mixed ZnS/PbS scales despite sulphide being the limiting reactant to individual Pb and Zn ions, while contrary results have been obtained by using scale prediction and lab testing under the same conditions.

The objective of this study was to investigate the interaction between Zn and Pb within solutions containing sulphide over a wide range of conditions including varying salinity (sulphate-free North Sea Seawater (SFNSSW) and Glenelg formation water (GFW)), temperature (50 and 95°C), time and Zn:S, and Pb:S molar ratios. Static scale formation experiments coupled with inductively coupled plasma (ICP) analysis, pH monitoring and particle size measurements have been used to analyse the system.

When a mixed Zn/Pb brine was combined with sulphide brine, Pb ions were completely stripped from solutions where sulphide was in excess to Pb. In this region, sulphide was partially consumed by Pb and thus the remaining sulphide reacted with Zn to form ZnS. On the other hand, when both Zn and Pb existed in excess to sulphide, single PbS formed despite the fact that both scales have very low solubility. Similar behaviour was observed when the temperature was increased from 50 to 95°C and GFW was used instead of SFNSSW.

This study showed that, under the conditions examined, PbS will always form preferentially to ZnS in a mixture even at high Zn:Pb molar ratios. Understanding the interaction between Zn and Pb in the presence of sulphide is essential for accurate interpretation of scale inhibition results and scale formation predictions.
Iron Sulfide Scale Dissolver for Downhole Application: Where Are We Now?
Authors: Wang Qiwei , Chen Tao , Chang Frank F. , Nasser Waleed Al , Shen Shouwen , Al-Badairy Hameed , Zaidi Syed , Liang Feng , Leal Jairo , Syafii Irfan , Al-Mukhles Amro
Published: March 2017

Downhole scale deposition in the Khuff sour gas wells in Saudi Arabia has been a persistent problem, which negatively affects operation and production. Scale deposits are composed of predominantly iron sulfides with other types of minerals also present. Mechanical descaling treatment, although expensive and time-consuming, is often required. Effective scale dissolver is highly desirable to enhance descaling efficiency and to reduce treatment cost. An ideal dissolver is required to have high scale dissolving power, no damage to downhole completion and well productivity, and minimal H2S liberation.

This paper presents the laboratory studies on the new scale dissolvers developed by service companies. These products have pH values ranging from strong acidic (pH < 2) to high alkaline (pH > 12). Dissolvers were evaluated for thermal stability, corrosivity to mild steel, and compatibility with formation water at downhole temperatures. The potentials of iron sulfide re-precipitation in spent solutions and free H2S generation were also examined. The qualified chemicals were then evaluated for their dissolving capacity using authigenic pyrrhotite and field scales at elevated temperatures.

The obtained results show that most effective acidic dissolvers evaluated in this study were very aggressive to low alloy carbon steel at downhole temperatures. For these with acceptable corrosivity, formation of iron sulfide reprecipitation in spent dissolvers and the generation of a large quantity of free H2S gas also prevented them from field application. Some dissolver products were disqualified due to incompatibility with formation water. Dissolvers with near neutral and alkaline pH values, in general, were inefficient to dissolve the heterogeneous iron sulfide scales. The performance of tested dissolvers varied with scales from different wells, attributed by differences in composition, microstructure, and the presence of hydrocarbon. Results also suggested that pyrite and marcasite were possibly formed during the dissolution process.

This paper presents an objective assessment on the currently available iron sulfide scale dissolvers, highlights the challenges on downhole scale dissolution in high temperature sour wells, and provides new insights on the scale dissolution process. The results suggest that further R&D efforts are required to develop more effective chemical solutions to mitigate the iron sulfide scale problem.
An Advanced, Balanced, and High-Performance Displacement Spacer System for Deepwater Formations
Authors: Gunawan Stanley , Fowler Drew A. , Mack Arthur
Published: March 2017

A successful wellbore displacement and clean-up is a critical step during well completion operations. A poor cleaning performance can lead to increased cost of completion operations, potential formation damage, and thus reduced oil and gas productions. Failure to achieve a balanced displacement system can lead to negative pressures on cement jobs and tie-backs, wellbore control issues, and wellbore instability.

Deepwater wells require a crucial and complete evaluation of a displacement system which will provide a balanced, effective, and efficient cleaning spacer system. Traditional displacement spacer systems typically consist of a solvent spacer and a surfactant spacer. A solvent spacer consisting of d-limonene is effective for removing oil-based drilling fluids from the wellbore; however, this is incompatible in water-based spacer systems and results in an underbalanced displacement system. On the other hand, a surfactant spacer is ineffective in displacing ester/isomerized olefin (IO) based drilling fluids. As the chemistry of drilling fluid additives become more diversified to accommodate various base oils, such as the blend of ester/IO used here, so too must the chemistry of cleaner/displacement additives to ensure appropriate compatibility.

On many occasions, barite residue from the weighted spacer was found to adhere strongly to pipe surfaces and be nearly impossible to remove chemically upon contact with the surfactant spacer. This issue can cause incomplete zonal isolation. A new, balanced, and high-performance displacement system (ADS-RD) was developed and optimized for its ability to effectively remove oil-based drilling fluids, barite residue, and water wet pipe surfaces. Lab test results showed that ADS-RD was fully compatible, consistently achieved an average of 98% cleaning efficiency, and yielded water wet pipe surfaces against the ester/IO based invert emulsion drilling fluids. ADS-RD also proved to be an effective and efficient solution to other oil-based invert emulsion drilling fluids.

This paper presents the testing program and lab test results for ADS-RD against a traditional displacement system with various oil-based invert emulsion drilling fluid systems with densities up to 14.8 lb/gal. This paper will also include cost savings and recommendations for field applications.
Scaling Risk and Inhibition Prediction of Carbonate Scale at High Temperature
Authors: Zhang Fangfu , Dai Zhaoyi , Zhang Zhang , Al-Saiari Hamad , Yan Fei , Bhandari Narayan , Ruan Gedeng , Liu Ya , Lu Yi-Tsung , Deng Guannan , Kan Amy T. , Tomson Mason B.
Published: March 2017

Calcium carbonate is the most common scales in oilfield and thus has been heavily studied. However, calcium carbonate scale problems continue to occur in oilfield causing significant economic loss. To better control carbonate scale, reliable models on carbonate scaling risk and inhibition predictions are clearly necessary, which motivates this study.

To develop such a model, it is necessary to gain a better understanding on mineral nucleation and inhibition kinetics based on experimental studies, which can correctly interpret field data and observations on carbonate scale occurrence. While heavily studied, what has been commonly ignored or failed to obtain in previous studies is a strict control of pH and CO2 pressure as well as a precise calculation of carbonate supersaturation in brine. Unlike BaSO4 or CaSO4, pH and CO2 pressure can strongly affect the supersaturation of carbonate in brine. Therefore, without careful control of pH and CO2 pressure and precise calculation of carbonate supersaturation, the reliability of data on carbonate scaling and inhibition kinetics can be questionable. Also, the difficulty in obtaining such a reliable control and calculation has limited studies on carbonate nucleation and inhibition kinetics to low temperature from 77-200 °F.

In this study, we have developed robust procedures in controlling experimental pH and CO2 pressure and calculating carbonate supersaturation from 39-350 °F. With newly developed apparatus and protocol, we studied the precipitation and inhibition kinetics of calcium carbonate in the time range of seconds to more than 24 hours. The inhibition efficiency of 9 commonly used inhibitors including both phosphonates and polymers were characterized at different temperature and supersaturation levels. Experimental results were consistent and reproducible. Furthermore, a novel inhibition model has been developed based on data from this study. Finally, field observations on carbonate scaling kinetics of a number of wells are used to validate our new model and minimum inhibitor concentrations observed in the field are consistent with model predictions. In conclusion, this study provides reliable methods in studying carbonate scales and the newly developed models can provide accurate predictions of scaling risk and inhibition, which can help optimize the scale treatment plan.
The Effect of Turbulence on Mineral Scale Control in Oilfield
Authors: Yan Fei , Zhang Fangfu , Bhandari Narayan , Ruan Gedeng , Alsaiari Hamad , Dai Zhaoyi , Liu Ya , Zhang Zhang , Lu Yi-Tsung , Deng Guannan , Kan Amy , Tomson Mason
Published: March 2017

Turbulent flow in oilfield pipes is very common, especially around chokes, tubing joints, and safety values. However, the effect of turbulence on mineral scale precipitation has not been well understood. The objective of this study was to investigate mineral scale formation and inhibition under turbulent conditions.

A novel tubing testing method has been developed to enable the study of turbulence in a tubing apparatus. In the tubing apparatus that consists of a long tubing (200 to 500 ft) and a high flow pump, high-velocity turbulent flow was generated. In another tubing experiment, a valve was installed in the tubing to examine the impact of valves on mineral scale precipitation. Barite scale formation and inhibition by inhibitors were investigated in turbulent flows by these novel approaches.

In the experiment, barium concentrations in the effluent of the tubing were measured to determine whether barite precipitation occurred in the tubing. Critical saturation index (SI) was determined by a series of experiments for both laminar and turbulent flow. Experimental results show the effect of turbulence depends on several factors such as reactant ratio and scale inhibitor. Under our test conditions, when the molar ratio of sulfate to barium is around one, we observe no difference in barite precipitation kinetics between laminar and turbulent flow without scale inhibitor; however, in the presence of scale inhibitor, barite precipitation kinetics is slightly faster in turbulent flow, or critical SI is higher in laminar flow than that in turbulent flow. When the molar ratio of sulfate to barium is high, critical SI of laminar flow is always slightly higher than turbulent flow with and without inhibitor. Two different tubing materials, i.e. polyethylene and stainless tubing, were both investigated in this study and experimental results shows the effect of turbulence on barite precipitation kinetics is the same for both materials. In the tubing with valve experiment, the valve in the tubing did not show an influence on barite precipitation kinetics.

This paper presents a novel tubing apparatus to investigate the effect of turbulence on scale control in oilfield. The findings in this paper will advance our understanding in scale control especially under turbulent conditions, and aid in developing optimal doses of scale inhibitors with regard to flow regimes.
Identification of New Chemical Formulation for Control of Metal Sulfides FeS, ZnS and PbS Scale Deposition
Authors: Bhandari N. , Ruan G. , Liu Y. , Zhang F. , Yan F. , Saiari H. A , Zhang Z. , Dai Z. , Lu Y. , Deng G. , Kan A. T. , Tomson M. B.
Published: March 2017

Metal sulfides such as iron sulfide (FeS), zinc sulfide (ZnS) and lead sulfide (PbS) scaling have been a persistent flow assurance problem in oil and gas production. FeS is ubiquitous in nature; however, ZnS and PbS are exotic scales but still pose significant scaling issues especially at HT wells. Efficient chemical treatment of those sulfides scales has not been found yet. Therefore, this study seeks to identify new chemical compound(s) to inhibit metal sulfide scale formation. A strictly anoxic static bottle test setup was designed and various chemical formulations were screened toward FeS, ZnS and PbS scale nucleation and growth inhibition. Thermal stability of the chemicals (150 °C for 18 hours) and phase transformation behavior of FeS scale with and without chemical treatment (75 °C for up to 10 days) were also conducted in glass container under anoxic environment. Aqueous phases as well as metal sulfide solid products were characterized using ICP-OES, X-ray diffraction, SEM, ATR-FTIR and other analytical techniques.

Our laboratory studies indicate that a polymeric compound containing amide or its derivative functionalities showed a promising effect by preventing metal sulfide scale deposition at threshold quantities. Specifically, the polymer did not inhibit the formation of the FeS, ZnS and PbS particles; however, it significantly influenced the growth and deposition behaviors by dispersing nano-particulates for an extended period of time. The thermal stability test results indicated that performance is not likely to be influenced at 150 °C even after 18 hours of ageing. Polymer treated and untreated FeS particulates were tested for heat induced phase transformation to pyrite and result indicated that polymer is highly efficient for inhibition of FeS phase transformation as well. Similarly, interference of performances towards metal sulfide dispersion due to the presence of other scaling materials (such as barite, iron oxides) and deposition tendency of dispersed metal sulfide particles onto flowlines were also tested and preliminary results look encouraging. Mechanistic aspect of polymer-particles interaction that prevents particle growth and deposition of FeS, ZnS and PbS scales are discussed. Despite its huge industrial and economic importance, an efficient solution of metal sulfide scale control is still an elusive goal. Based on our current laboratory results, it is believed that these polymers will provide a novel chemical treatment option for simultaneous control of these three sulfides (FeS, ZnS and PbS) scaling issues.
Preparation and Evaluation of Thermo- and Salinity-Responsive Hydrogel as Intelligent Plugging Agent
Authors: Xue Yan , Wang Xinyong , Zhang Bo , Wei Bing , Ye Zhongbin
Published: March 2017

The swellable hydrogel particles have been developed as effective plugging agents. However, the harsh conditions would significantly detract the performance of conventional plugging agents. To address the problem, an amphoteric hydrogel (IHPA) modified by zwitterionic groups was successfully developed, which presented distinctive thermo- and salt-responsiveness. Environment Scanning Electron Microscopy (ESEM) images of swollen IHPA showed its multiporous structure contributing to its water absorptivity. The water absorption and swelling capacity of IHPA were systematically studied at various temperatures using water and different salines. The sudden increase of the swelling capacity of the hydrogels upon temperature and/or salinity, caused by the alteration of zwitterionic self-association, promised them as intelligent plugging agents. The plugging simulating tests indicated that IHPA possessed excellent plugging performance at 80°C with a plugging efficiency of 93.8% compared with the efficiency of only 33.3% at 20°C
Effectiveness of Polycarboxylate Dispersants in Enhancing the Fluid Loss Performance of Cellulose Ethers
Authors: Moumin Mouala , Plank Johann
Published: March 2017

This paper investigates the performance of different kinds of polycarboxylate (PCE) dispersants in combination with cellulose ethers as fluid loss additives and presents their influence on the fluid loss. The objective was to find out whether PCEs can better enhance the fluid loss performance of HECs than the currently applied acetone-based dispersant (AFS). Two different polycarboxylates were synthesized via free radical copolymerization using either methacrylate ester or isoprenyl ether as macromonomers and tested. The AFS polycondensate and the hydroxyethyl cellulose (HEC) were commercial samples. The impact of the PCE and AFS dispersants on the fluid loss of cement slurries achieved from hydroxyethyl cellulose was investigated via static fluid loss and rheology measurements. All PCE polymers improved the fluid loss performance of HEC significantly more than AFS; i.e. they required considerably lower dosages than AFS to achieve the same volume of fluid loss. For example, at 27 °C the addition of 0.1 % bwoc PCE to 0.4 % HEC improved the fluid loss from 250 mL/30 min to 50 mL/30 min. For the same effect, 0.4 % of AFS were needed. Most important, such low fluid loss values were achieved at very thin filter cakes, indicating that although the PCEs reduced slurry rheology considerably, no sedimentation had occurred which can also lead to low fluid loss, but is highly undesirable. Furthermore, a linear correlation between cement slurry rheology and fluid loss was observed: The stronger the dispersing effect of the PCE, the better is the fluid loss control. Among the PCEs tested, the isoprenol ether-based copolymer stood out as performing best. Dynamic light-scattering measurements revealed that the presence of PCEs strongly enhances the association of the HEC molecules, thus improving their ability to plug cement filter cake pores.
Using Properties in Nature to Modify Proppant Surfaces and Increase Flow
Authors: Bestaoui-Spurr Naima , Sun Steve , Williams Vanessa , Volk Alyssa , Nguyen Susan
Published: March 2017

In oil and gas wells that are hydraulically fractured, wetting properties of surfaces (formation and proppant) significantly affect hydrocarbon and liquid displacement. During the life of a well, the water saturation of surfaces changes, leading to reduction of relative permeability to oil or gas and consequently affecting production. In order to reverse the formation to a reduced water wet state and improve the movement of hydrocarbons, strong water-wet surfactant is pumped. The surfactant is then adsorbed onto the surfaces reducing the capillary pressure and water saturation within the porous systems. This is, however, not a permanent solution, as the surfactant is washed out over time. A more permanent and robust solution is needed.

Nature encompasses many examples of biological systems and surfaces that are permanent and have special wettability and interfacial interaction with fluids. Research and development within the last decade in bio-mimicking nature has been fruitful and led to the development of many new surfaces such as superhydrophobic, ice phobic and low-drag surfaces.

In this work we apply some of the knowledge and principles found in nature to modify proppant surfaces (silica sand and ceramic proppant) in order to study how wettability will affect the fluids recovery and their interaction with the solid surfaces. Nanotechnology was used to deposit hydrophobic/oleophobic moieties onto the proppant surfaces, and several surface modifiers were tested. These molecules were covalently bonded to the surfaces. The new surfaces were characterized for wettability and flow to water and oil. A new proppant that show promises for improved stimulation fluids recovery and flow was identified and further developed.
Nanomaterials-Enhanced High-Temperature Viscoelastic Surfactant VES Well Treatment Fluids
Authors: Ozden Sehmus , Li Leiming , Al-Muntasheri Ghaithan A. , Liang Feng
Published: March 2017

Nanomaterials are being implemented in more and more industries due to their unique properties and performances at the nanoscale. In the oilfield, nanomaterials can significantly improve the performances of well treatment fluids including hydraulic fracturing fluids. Fluids based on polymers such as polysaccharides are widely used in the oilfield as fracturing fluids, but these fluids can have some limitations. For example, high molecular weight and incomplete breaking of these polymers can cause serious formation damage.

An alternative material is viscoelastic surfactant (VES) which has been used for fracturing and acid jobs. VES-based fluids are low molecular weight in nature and show minimum formation and conductivity damage. Yet, there remain challenges associated with their use such as limited thermal stability and high leakoff rate. The use of nanomaterials such as MgO and ZnO was found to enhance their thermal stability and leakoff properties at temperatures up to 250°F. For wells with higher bottomhole temperatures, the nanomaterials that can significantly enhance the performances of the VES fluids at 350+°F will be much sought after.

In this paper, we report the use of a number of the selected nanomaterials to enhance the VES gels at temperatures up to 350°F or higher. In one example, the addition of about 0.1 wt% nanomaterial-I enhanced the viscosity of the VES fluid by about 24% averaged over the temperature range from 250 to 350°F. In another example, nanomaterial-II at a dose of about 0.04 wt% enhanced the viscosity of the VES fluid by about 23% averaged over the temperature range from 250 to 350°F. Additionally, measurements showed that the viscosity of the VES fluids remained above 110 cP (at 100 s-1 shear rate) for over two hours at 350°F with the addition of either nanomaterial-I or nanomaterial-II. The fluid stability at elevated temperatures could also be improved with the selection of other nanomaterials.

This paper will discuss the applications for these nanomaterials in hydraulic fracturing and other oilfield operations under high temperature conditions, based on the laboratory test results that will be shared in detail. This technology could open the door for more advancement in hydraulic fracturing with non-damaging VES systems at high temperatures.
Synthesis, Properties and HT Performance of a Novel Cement Fluid Loss Polymer Modified with Phosphate Groups
Authors: Hurnaus Thomas , Echt Timon , Plank Johann
Published: March 2017

Fluid loss additives (FLAs) based on 2-acrylamido-2-tert.-butyl sulfonic acid (ATBS) provide fluid loss control by reducing filtercake permeability through polymer adsorption. However, when highly anionic dispersants or retarders are present in the slurry, adsorption of the ATBS polymer is hindered resulting in high fluid loss. To overcome this problem, ATBS - N,N-dimethyl acrylamide (NNDMA) copolymers were modified with phosphate groups to enhance their affinity to the surface of cement and make them more robust in the presence of other anionic additives. Fluid loss tests revealed that modification of the ATBS-NNDMA copolymer with phosphate groups greatly improves its fluid loss performance in both fresh and sea water cement slurries. Additionally, it extends its temperature stability up to 150 °C (300 °F), as was observed in stirred fluid loss tests. Furthermore, the excellent fluid loss performance of the phosphate-modified FLA remained unaffected in the presence of AFS dispersant or ATBS-co-acrylic acid retarder, while the effectiveness of the conventional, non-phosphated FLA was severely impeded by these additives. Adsorption measurements illustrated that the superior fluid loss performance can be attributed to stronger adsorption of the phosphated FLA on cement. Adsorbed layer thickness measurements elucidated that the phosphated FLA adsorbs in a "train" like conformation on cement as compared to the conventional ATBS-NNDMA copolymer which attains a "loop"-type conformation.
New Polymeric High Temperature Cement Retarder with Synergistic Suspending Aid Property in Fluid Loss Control Polymers
Authors: Pernites Roderick , Clark Jordan , Santra Ashok
Published: March 2017

This paper presents a new high temperature retarder that can effectively delay the setting time of an oil and gas cement up to 450 °F via a single polymer only instead of the usual combination of synthetic copolymer of 2-acrylamido-2-methylpropane sulfonic acid and acrylic acid (AMPS®/AA)-based or natural lignosulfonate-based polymer retarder along with an intensifier small organic molecules like tartaric, citric, or gluconic acids that are relatively costly and sometimes degrade the performance of cement fluid loss control polymer. More interestingly, this new differentiated polymer cement retarder provides unique synergistic property in presence of an AMPS®-based cement fluid loss control polymer that is giving additional suspension capability useful for water-extended lightweight density cement slurry; thereby, eliminating the need for an extra viscosifying agent and/or high temperature suspending aid. With the use of this new polymer retarder, complicated cement design is actually simplified having less additive in the mixture, giving the advantage of better logistics, easier operations, and cheaper economics.
Improved Disproportionate Permeability Reduction of Silicate-Gelant Treatments: A Laboratory Scale Approach
Authors: Askarinezhad Reza , Hatzignatiou Dimitrios G.
Published: March 2017

A new experimental steady-state, two-phase chemical-system placement for Disproportionate Permeability Reduction (DPR) treatment has been recently established using water-soluble sodium silicate gelants. DPR treatment application in oil-wet formations has shown to be effective in reducing the water permeability compared to that of the oil phase. This work focuses on a modified approach of the newly established DPR treatment aimed to improve the treatment effectiveness.

Steady-state, two-phase placement of a DPR-fluid/oil is used not only to better control the formation saturation conditions but also to ensure presence of oil-phase path inside the porous medium. The DPR treatment performance is evaluated based on steady and unsteady-state permeability measurements conducted after treatment. DPR treatments were performed on oil-wet Berea core samples at both the same and lower water cuts (formation water saturation) compared to pre-treatment condition. Water-wet cores were treated chemically to alter their wettability to oil-wet. Measured phase-permeability curves together with recovery curves and spontaneous imbibition results were used to characterize the core wettability.

Results show potential positive DPR effects in all cases resulting in higher water-phase permeability reduction than in oil phase. However, if the DPR fluid placement is carried out at watercut conditions that are lower than the ones existing prior to treatment, the reduction in oil phase permeability is less severe resulting in a more beneficial DPR effect. It is of course worth mentioning that in the latter case, the residual resistance factor of the water phase also experiences a significant reduction compared to the former case but it is still higher compared to the one of the oil phase thus leading to a positive DPR treatment. Experiments conducted at different initial water cuts (high, medium, low) resulted to similar DPR effects when the silicate gelant was placed at the same conditions.

The importance of this approach is that DPR treatments can now be conducted at later production stages (higher water cuts) while achieving similar beneficial treatment effects related to phase permeability reductions. On the other hand, the reductions of the relative permeabilities seen in prolific (high oil saturation) zones of a multilayered system dictates the use of selective placement of the DPR fluid versus the bullhead injection (a) to minimize risks for post-treatment reductions of well oil production rates and (b) to enhance treatment success for post-treatment reduction of water production rates.
Nanocellulose and Its Derivatives for High-Performance Water-Based Fluids
Authors: Hall Lee J. , Deville Jay P. , Araujo Carlos Salas , Li Shuai , Rojas Orlando J.
Published: March 2017

Water-based drilling fluids provide an economical and environmentally attractive option for wellbore construction. Despite the development of high performance water-based fluids, consistent demonstration of drilling performance comparable to oil-based fluids has proven to be elusive. Both traditional and high-performance water-based systems typically use biopolymers to provide filtration control, viscosity, and suspension properties. These biopolymers include naturally occurring materials, such as celluloses, starches, hydrocolloids, and bacterially engineered polymers, such as xanthan gum. Although several options exist, new materials are always desired to improve efficiency or enhance high pressure, high temperature (HPHT) performance. Recently identified nano-structured biomaterials, such as nanocelluloses, have been used in the development of advanced materials systems because of their outstanding mechanical, structuring, and thermal properties; they are also potent viscosifiers at relatively low concentrations (~0.5 wt %). This paper explores the rheological, thermal, and fluid loss properties of as-produced and covalently modified cellulose nanofibers in saline water-based fluids. Results are compared to a commercial xanthan gum viscosifier as used in saline water-based drilling fluids.

Cellulose nanofibrils were produced from kraft pulp wood fibers by using known methods based on mechanical shearing. Using a standard concentration in water, measurements were made of complex rheology, filtration (API LPLT test), and equivalent and total surface charge. The nanocellulose materials were then modified by means of simple chemical reactions to tailor the surface properties, and then compared to the original material. The same battery of tests was run in control experiments performed with a commercial xanthan gum-based viscosifier.

By modifying the surface of nanocellulose with new covalently bound functional groups, a wide range of fluid behaviors was achieved through the control of the resulting changes in surface chemistry. Unlike nanomaterials based on graphitic carbon, such as nanotubes and graphene, cellulose features a natural polymer backbone chemistry having three available hydroxyl sites on each cellulose repeat unit. The secondary alcohol group at position 6 on the β-D-glucopyranose ring is especially well-suited for site-selective reactions, such as oxidation. The new surfaces created with each new functional group provide different modes of interaction with salt ions, water molecules, and other biopolymers in the fluid to change fluid properties.

This work introduces a new renewable, non-toxic, and potentially less expensive alternative to synthetic polymers for viscosity and filtration control in high-performance water-based drilling and completion fluids. Furthermore, nanocellulose materials can be modified through simple chemical reactions to provide improved performance or to tailor their effects and interactions with other components.
Development, Testing and Field Application of a Novel Combination Foamer-Iron Sulfide Scale Inhibitor-Corrosion Inhibitor in East Texas
Authors: Wylde Jonathan J. , Turner Nick , Austill Mark , Okocha Cyril , Obeyesekere Nihal
Published: March 2017

Production in East Texas has a long and rich history in both liquid and gas plays. This paper concerns wet gas production in the Fairfield, TX area and a unique challenge that was overcome by a collaboration between operator and service company. The application in question spans many wells in the Central and East Texas area where a common challenge was production of gas with associated corrosive fluids that led to significant deposition of iron sulfide scale in the production tubing.

This paper details the unique challenge of creating a single chemistry that not only can successfully deliquify the wells when pumped on a continuous basis but also one that can reduce the corrosion and prevent the build-up of carbonate scales and most importantly iron sulfide scale in the production tubing. Development work presented includes laboratory and field foamer testing, iron sulfide scale testing, and autoclave corrosion testing. This was made all the more challenging due to the high downhole temperatures of 300°F with a pressure of 1,000 psi and a mixed sweet / sour gas with a composition of 2.2mol% CO2 and 0.75mol% H2S.

Testing showed that application of these products up to 6,000 ppm was able to stabilize gas production, reduce the corrosion to acceptable levels and prevent the deposition of iron sulfide scale in static and dynamic tests.

Extensive detail is provided on the field trials and the monitoring regimen that was put in place to monitor all functionalities provided by this chemistry. As this was across a whole host of different well types, significant data was generated and a wealth of information and lessons learned for the industry can be extracted from it.

The paper concludes with the overall lessons learned and summary of the validity of this technology and how it could potentially be a game changer for the industry at large in East Texas where gas well deliquification combined with corrosion and scale formation is a shared challenge.
A Re-Evaluation of Reservoir Souring Patterns and Effect of Mitigation in a Mature North Sea Field
Authors: Mitchell Anthony F. , Skjevrak Ingun , Waage Jone
Published: March 2017

Subsurface generation of hydrogen sulphide (H2S), commonly known as reservoir souring, is a clearly identified but, still not fully understood phenomenon associated with water injection for secondary oil recovery. A large number of North Sea fields have been under seawater injection for many years, yet the majority are relatively poorly documented in terms of how and when souring developed and the amount of H2S being generated between injector and producer well pairs.

As part of ongoing work to verify the results of reservoir souring simulations, using empirical data, an exercise was undertaken to collate souring information from a number of older fields, with the objective of attempting to identify trends in, or factors impacting, souring development. A review of available historic data from the Gullfaks field was made; linking measured H2S values, well test data, water analyses and tracer data to identify long term souring patterns, the amount of H2S produced relative to injected water and to determine the effectiveness of the different mitigation strategies used in the field. The Gullfaks field in the Norwegian sector of the North Sea began production in 1985 and has been widely cited in connection with the introduction of nitrate treatment as a mitigation method for reservoir souring.

A number of key observations were made for Gullfaks. Souring development appears to follow a dual pattern of initial production of H2S, coincident with or shortly after breakthrough of injection water, followed by a subsequent decline; thereafter, sometimes several years later, a gradual increase to much higher levels is recorded. This implies that different types of souring patterns are being observed.

On the basis of improved understanding of souring development and data availability, a review of the effectiveness of mitigation techniques used in the field was undertaken. The interpretation indicates that the previously reported effect attributed to use of nitrate could also be explained by the natural progress of souring development in the field.

The work flow and methods of data interpretation opens the way to further full field evaluations as a means of improving the precision of souring simulation and assessment of mitigation methods
Scale and Corrosion Inhibitor Evaluation under High Shear Flow Conditions
Authors: Nichols David A. , Thomson Hunter , Simpson Caroline , Graham Gordon M.
Published: March 2017

Scale and corrosion testing under high surface shear flow conditions, and selection of effective inhibitors, is of increasing importance in oilfield production. Extremely high wall shear stresses, up to 10,000 Pa, can be generated in production systems, for example in inflow control devices, and as such there is a need for high shear corrosion and chemical testing techniques. A jet impingement test technique is presented that enables performance testing of both scale and corrosion inhibitors under these challenging conditions and demonstrates the effect of elevated shear on inhibitor performance.

A test system has been developed that allows routine laboratory evaluation of scale and corrosion processes at moderate to high shear stresses using a jet impingement method. A series of tests has been conducted to determine the extent of scale deposition and corrosion observed with a mild scaling system, both independently and combined, and then to assess the effectiveness of inhibitors under high shear conditions. Static tests and low shear rotating cylinder tests have been carried out with the same brine system to allow comparison of results from the different methods.

The results show that the jet impingement approach is effective in generating scale deposition and corrosion under the high shear, field representative conditions. The effect of the scale and corrosion processes occurring simultaneously in the same system was demonstrated. Both scale inhibitor and corrosion inhibitor performance were found to be affected by the flow conditions with higher concentrations of each being required as surface shear stress was increased although this was also dependent on the chemical nature of the inhibitors. Comparison of the jet impingement results with those obtained from static and rotating cylinder methods showed that the developed technique is more suitable and allows both scale and corrosion processes to be observed in the same system, under the same hydrodynamic conditions.

This test method therefore provides an additional laboratory technique that can be used to evaluate both scale deposition and corrosion under very high shear stresses that cannot be readily achieved by alternative approaches. This work also highlights the importance of testing under field representative conditions and advances the understanding of inhibitor performance in these systems.
Wax and Paraffin Control by Fracturing Fluids: Understanding Mode of Actions and Benefits of Water-Dispersible Wax Inhibitors
Authors: Mahmoudkhani Amir , Feustel Michael , Reimann Werner , Krull Matthias
Published: March 2017

During hydraulic fracturing operations in oil wells, the equilibrium balance of the crude oil is disrupted once high-pressure fluids are injected into the formation. Fluid temperature is often less than reservoir temperature, and if the formation is cooled below the cloud point, paraffin precipitates may deposit in the formation pores and faces as fractures develop. For paraffin-rich reservoirs, such as shale oil, damage caused by wax deposition at the fracture skin can cause decreased production, slow or hard to clean up wellbores, or failure to achieve predicted maximum recovery.

Developments in horizontal drilling and hydraulic fracturing during the past decade provided the industry with a versatile tool that utilized fracturing fluids as a carrier to deliver chemical additives in the form of liquids or solids deep into the reservoir. Chemistries, such as scale, wax and asphaltene inhibitors, are impregnated or infused in porous solids and placed into fractures during the fracturing job, which can provide long-term well protection and production control. Water-soluble additives can be easily formulated within these fluids and/or delivered via slow-release solid products, but the delivery of water-insoluble additives are difficult on an equivalent base. Non-polar additives are not going to be released from solid carriers since the water cut is relatively high within one to four weeks of a hydraulic fracturing job. The risk of organic deposition persists if minimum inhibition concentration of chemical additive is not attained during and after the job.

The scope of discussion in this paper will largely focus on water-dispersible systems, in particular to colloidal microdispersion, since they are the most prevalent type of dispersions found to be viable for hydraulic fracturing applications. A methodology is presented that demonstrates the advantages of water-dispersible wax inhibitors that prevent paraffin deposition from waxy crudes in the Bakken, Permian and Eagle Ford basins while complementing long-term control further provided by solid wax inhibitors.

This study adapted a novel approach by incorporating wax and paraffin control chemistries into a microdispersion system that is fully dispersible in water. In such micron-sized liquid-in-liquid or solid-in-liquid colloidal dispersed systems, active chemistries comprising polymers from poly (EVA), poly (alkylacrylate), poly (EVA-alkylacrylate), poly (α-olefine-MAA) esters/amides/imides, and selected dispersants and surfactants are brought together to deliver immediateand short-term inhibition for paraffin wax control.
The Most Efficient Use of Acoustic Sand Monitors. Lessons Learned from Many Years of Operation
Authors: Haugsdal Torbjoern
Published: March 2017

Sand production has been a critical factor regard the safety and the economics of many oil and gas fields. The first acoustic sand monitor was commissioned in 1995. Since then, a significant amount of time and money have been spent on controlling sand production.

A critical factor has always been accuracy and reliability of the systems, with different approaches used to accommodate the risk and the challenges different fields present.

This presentation will look back at how things were done in the beginning, what we have learned, and how things have changed. It will also cover the technical evolution since then.

We will look at the challenges still to be solved, and the experience gained in the areas of sand production, sand transport and sand monitoring.

The presentation will be supported by field cases.
Leakage Calculator for Plugged and Abandoned Wells
Authors: Ford Eric P. , Moeinikia Fatemeh , Lohne Hans Petter , Arild Øystein , Majoumerd Mohammad Mansouri , Fjelde Kjell Kåre
Published: March 2017

Today's practice on the Norwegian Continental Shelf when designing solutions for permanent plug and abandonment (P&A) complies with NORSOK Standard D-010. This is a prescriptive approach to P&A, as opposed to a "fit for purpose" risk-based approach. A risk-based approach means that any given P&A solution is expressed in terms of the leakage risk, which can be formulated in terms of the following quantities; the probability that the (permanent) barrier system will fail in a given time period and the corresponding consequence in terms of leakage to the environment.

As a part of building a leakage risk model for permanently plugged and abandoned wells, a simple leakage rate calculator has been developed for quick evaluation of the leakage potential from a given (permanent) well barrier solution. The leakage potential from the well can then be quantitatively assessed taking into account different leakage pathways including leakage through bulk cement, through cement cracks and through micro-annuli along cement interfaces.

In the paper, we will provide models to estimate leakage rate for each leakage pathway and show how to integrate them in an overall leakage calculator, to obtain a description of leakage flow from the reservoir through failed barriers to the environment. The information and input parameters needed to achieve this will be discussed, and uncertain parameters will be treated probabilistically, thus allowing for expressing uncertainty in the leakage rate estimate.

Results from the leakage calculator will be demonstrated on a synthetic case, showing variants of a permanently plugged and abandoned well.