bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Stimulation Using a Solid, Proppant-Sized, Paraffin Inhibitor to Reduce Costs and Increase Production for a South Texas, Eagle Ford Shale Oil Operator
Authors: Szymozak Stephen , Gupta D.V. Satya , Steiner William , Bolton Stephen , Romano John 
Published: June 2014

Abstract
An US Eagle Ford Shale operator experienced downhole paraffin deposition in recently completed shale oil wells. The deposition occurred in the tubulars and in the flow lines. To control deposition the operator added to the fracture a proppant-like, slow-release particle onto which a paraffin inhibitor had been adsorbed. The particle is designed to slowly release the adsorbed paraffin inhibitor into the bulk oil as it flows through the propped zone and to inhibit paraffin deposition.
Horizontal, multi-stage hydraulic fractures are becoming the standard stimulation practice in the oil bearing shale oil fields in the US. This operator saw a financial and operational benefit in establishing long-term paraffin treatment with a single application. The operator opted to use this solid inhibitor to extend the treatment life and to reduce subsequent intervention costs for paraffin removal.
The prior practice in this field was to complete the wells and then to apply a paraffin treatment and remediation program as necessary. In the offset wells to which the solid product was compared the operator normally saw paraffin deposition after approximately three months of production. The operator selected seventeen wells for completion using the solid paraffin inhibitor. After ten months of production, for the first wells treated, the operator has noted no paraffin related issues.
Paraffin can deposit in the formation, near well bore, tubulars and surface facilities when the thermodynamic conditions favor deposition in order for the fluid to re-establish equilibrium. Wax deposition reduces production and increases operational expense. By incorporating a slow-releasing, solid, paraffin inhibitor-infused particle into the proppant stages of the hydraulic fracture the operator realized reduced intervention expense without adding significant cost to the fracture.
Integrating Technology for Improving Recovery and Field Redevelopment in a Highly Heterogeneous Carbonate Reservoir
Authors: Gupta Shilpi , Sinha Ravi , Verma Vibhor , Kumar Ajit , Singh R. K. , Swain Saraswat , Pandey Arun , Singh P. P. , Hinge P. 
Published: June 2014

Abstract
Field XYZ located in the western offshore India is a multi-pay, multi-layered heterogeneous Carbonate reservoir having lateral discontinuities. Discontinuous layers and scale deposition and near well bore damage have led to multi-dimensional problems related to both upper and lower completions reducing ultimate field recovery. Workover attempts like re-perforation, additional perforations and plugging, artificial lift by electrical submersible pump (ESP) and secondary recovery by water injection were implemented to maximize the field recovery. However, any work over had only short term impact on production increase.Also, water injection and ESP performance were inefficient. Production History showed cyclic decline in production with time. Identifying and locating the layers' discontinuities became crucial in candidate selection and design of efficient injection pattern, artificial lift, completion and work over in existing and new infill wells.
The following case study presents a workflow involving multi well geological, petro physical and time lapse formation pressure data and production logs to identify and locate lateral discontinuity within a pay of the field. As a result, the reservoir pressure support attempts using water injection methods were proved to be suboptimal. Furthermore, this workflow has been successfully implemented for identifying location of infill wells and candidate selection and design of wells to be completed with ESP.
Seven future candidates for ESP were recognized. Additionally, locations of three new infill wells are identified and a strategic layer wise completion was designed and executed.
Implementation of the results increased production from the field by 27%.
The Impact of Kinetic Hydrate Inhibitors Within Produced Water on Water Injection/Disposal Wells
Authors: Jordan M. M , Weathers T. M. , Jones R. A. , Sutherland L. , Giddings D. M. , Abla M. 
Published: June 2014

Abstract
Within the Middle East region the development of large gas accumulation has resulted in a need for hydrate control within the produced fluids during the winter months. Development of kinetic hydrate inhibitors (KHI) as an alternative to thermodynamic hydrate inhibitors (THI) such as methanol or mono ethylene glycol (MEG) has resulted in a significant reduction in process equipment size and associated operational costs but the disposal of the resulting KHI that predominately partions into the produced water and corrosion inhibitor constantly added to production lines has raised concerns about formation damage within the injection/disposal wells under matrix flow conditions
This paper will present details from a set of corefloods which look at produced water re injection (PWRI) under matrix flow conditions within carbonate cores and the observed damage such KHI and KHI/CI solutions can produce within Arab D formation rock. The coreflood tests generated pressure profiles, cation, pH and KHI concentration within the coreflood effluent during the injection of these fluids to fully understand the process occurring within the rock (dissolution, ion exchange, precipitation/adsorption, filtration). The study then looked at mitigation methods for the damage that could be potentially induced and then based on understanding the two generations of KHI and associated corrosion inhibitor molecule structure what changes could be made to the produced fluid composition to eliminate the damage from forming in the first place.
The paper outlines the mechanism of damage and mitigation to a flow assurance challenge that is receiving a significant amount of focus within the Middle East region at this time.
Using NMR technology to Study the Flow of Fracture Fluids inside Shale Formations
Authors: Gomaa Ahmed M. , Zhang Boyang , Qu Qi , Nelson Scott , Chen Jinhong 
Published: June 2014

Abstract
The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracturing fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of microfractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. Nuclear Magnetic Resonance (NMR) technology has been explored to study the propagation of fracturing fluids inside shale cores before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), and injection pressure were evaluated.
Based on experimental results, the leakoff rate inside the shale formation during the hydraulic fracturing treatment can be calculated using NMR technology. NMR confirmed that slickwater and a higher-viscosity fracturing fluid propagated into the larger pores and existing microfractures. Increasing the viscosity from 1 to 200 cP reduced the leakoff rate by 6.5 times. This reduction can significantly affect the shape of the fracture and the corresponding breakdown pressure. Leakoff rate increased 2.65 times by doubling the injection pressure because increasing the injection pressure also increases the communication among the pores, and may ‘balloon’ the large pores, or increase the microfracture density. Reactive fluids, such as HCl acid, show an infinite value of leakoff as they were found to break through the shale core, even in shale having low HCl solubility (less than 2 wt%).
Insights from the Evaluation of Sand Control Performance in Offshore Brazilian Southeast
Authors: da Cunha Carolina B. , Pereira A. Z. , da Silva Mario G. , Calderon A. , de Sá A. Nicolino , Fernandes Paulo D. 
Published: June 2014

Abstract
The performance of sand control systems is an important issue, constantly addressed in several technical forums. In the scenario of offshore Brazilian Southeast, improved sand control techniques solved the problems of formation damage and flow restrictions, but the well production conditions caused several well problems, even sand control failure. The analysis of producer wells with sand control has shown an interesting behavior, confronting the concepts adopted by Petrobras. As expected, for producer wells, the failure rate is low for open hole gravel pack and fracpack, higher for cased hole gravel pack and very high for SAS and ESS. However, in the case of injection wells, no appreciable failure was observed, regardless of the sand control type, which suggest the possibility of expand the application of SAS, and even ESS, for this type of well. Surprisingly, the few failures observed in horizontal wells did not occur in partially packed HOHGP. Those partially packed HOHGP (premature screen out) constitute 8% of total HOHGP operations, considering producers and injectors, with operational lives similar to the fully packed ones. This behavior suggests that the effect created by the gravel is essential only in the HOHGP near heel region, indicating that the OHGP could, potentially, be replaced by the association of SAS with ICD, modifying the sand control profile in the Brazilian Southeast. This work presents a performance analisys of sand control techniques, with conclusions and suggestions based on the data of 680 wells, covering 30 years of sand control operations in offshore Brazilian Southeast.
Development of Polyglycolic and Polylactic Acid Fluid-loss Control Materials for Fracturing Fluids
Authors: Yoshimura Koichi , Matsui Hitoshi , Morita Nobuo 
Published: June 2014

Abstract
Fluid-loss is significant for the standard fracturing-fluids without adding solid materials. One method to reduce fluid-loss is to add silica flour, although it reduces fracture conductivity. Other methods are to use wall building polymers. However, the fluid-loss is still significant and complete removal of wall building materials are not possible even with breakers. We found that powder, granular and fibrous materials made of Polyglycolic Acid (PGA) or Polylactic Acid (PLA) are very suitable for fluid-loss agents since they are as strong as rock, while they dissolve as liquid acids after applications.
Fluid-loss tests are conducted using the standard API slot tester and filtrate loss tester, mixing powders, grains and fiber, all made of PGA or PLA in frac polymer fluids. Ratio of grains, powder and fiber is optimized to minimize fluid-loss for porous media and fractured porous media. Then, the changes of particle size are measured under heated conditions. Fracture simulation studies are also conducted using a 3D fracture boundary element model to compare the fluid efficiency of the fracturing fluids with and without the PLA and PGA particles.
The results show that the capability of preventing fluid-loss and plugging micro-cracks is maintained for the porous filters and small slots within reasonable time period. For short term applications less than 3 hours, both PGA and PLA fluid-loss agents are stable when the temperature is less than 212 °F. Mixing these materials often provides more efficient properties to reduce fluid-loss and to bridge micro-cracks. No residues are left after experiments if the fracturing fluid is kept being heated for 24 hours. The amount of the PGA and PLA fluid-loss agents required to reduce the fluid-loss is not significant. Hence, their field applications are feasible judging the cost and the benefit.
The advantage in using these materials is that they turn from solid to liquid after applications so that no formation damage and no proppants conductivity damage occurs. The fluid-loss is also significantly reduced with the powder particles.
In addition, because the PGA and PLA materials are degradable, solids with arbitrary sizes and shapes may be used as long as they control fluid-loss and plug fine fractures. Their applications are not only limited to reducing fluid-loss but they may be used for engineering fracture design to enhance the fracture conductivity.
Sulphide Scale Co-Precipitation with Calcium Carbonate
Authors: Okocha C. , Sorbie K. S. 
Published: June 2014

Abstract
Carbonate-sulphide mixed scale problems have been reported when water is produced from carbonate reservoirs. The mechanistic understanding of CaCO3 co-precipitation with sulphide scales has not been very extensively studied to date. This paper presents a study of the interactions of lead/zinc sulphides co-precipitating with calcite. The relationship between bulk precipitation and deposition on a metal surface of the mixed carbonate-sulphide scales is examined when the mixed scales begin to nucleate, agglomerate and grow. CaCO3 crystals appears to transform from a stable rhombohedral crystal to an orthormbic variant of this crystal form and then to an extreme acircular crystal in the presence of sulphide scales.
These transformations are more significant in the presence of the polymeric scale inhibitor, PPCA, where the CaCO3 crystals formed on the metal surface are highly distorted, while those formed in bulk solution solution are hardly changed. The nature of these mixed crystals may indicate that mixed sulphide scales tends to prefer forming in solution rather than adhering to metal surfaces in protected zones. Thus, the mixed sulphide scale may be controlled in one area but unprotected in other regions.
Calculating Pore Size Distribution by Using Capillary Pressure
Authors: Ling Kegang , Han Guoqing , Shen Zheng , Ghalambor Ali , He Jun , Pei Peng 
Published: June 2014

Abstract
Pore size distribution is an important parameter in quantifying reservoir heterogeneity. A thorough understanding of different pore sizes in the rock provides a solid base for reservoir development plan and makes an accurate estimation of volumetric sweep efficiency possible. For instance, more certainty in determining pore size distribution can be valuable in accurately predicting the hydraulic flow units which in-turn affects building more reliable geological and petrophysical models for reservoirs. Conventional rock porosity estimation from core and well log only provides porosity without pore size distribution. Therefore methods used to estimate percentages of different pore size are highly desired. Our novel approach is engineered to address this issue.
Starting from the capillary pressure data obtained in special core analysis, we developed a correlation in which capillary pressure is expressed as a function of pore size, water saturation, and other petrophysical parameters, which are readily obtained from well log interpretation. Through this correlation each pore size is corresponding to a unique capillary pressure and water saturation. Therefore, the calculation of percentage of each pore size can be accomplished.
The pore size distribution from our method is not only vital for two and multiphase flows in reservoirs such as water drive oil and gas drive reservoirs, but also crucial in estimating the percentage of reservoir volume that can be depleted at the abandonment reservoir pressure. Thus a reliable estimated ultimate recovery can be achieved without adding much cost and time since capillary pressure and well log data that are used as inputs for calculation are readily available. Therefore, the proposed method fills the big gap in reservoir characterization and is a useful tool to supplement other methods in reserve evaluation.
Enhancing Proppant Pack Conductivity With Consolidation and Agglomeration Performance: A Laboratory Study
Authors: Vo L. K. , Nguyen P. D. , Liang F. , Parton C. 
Published: June 2014

Abstract
To control proppant flowback during well production, proppant is often coated with a curable resin to obtain bonding between grains. However, current curable resin systems often have short cure times, allowing the resin coating on proppant to cure prematurely before complete placement into the target fractures, or creating operational issues if removal of the proppant from the wellbore is required. As another option, proppant can be coated with a tackifier polymer to maintain propped fracture conductivity by mitigating migration and intrusion of formation particulates into the proppant pack. The use of only a tackifier polymer does not offer sufficient cohesion to lock the proppant in place under high production flow rates. This paper presents the results of a laboratory study to demonstrate and quantify the performance of a new resin system that provides both tackiness and the option of delayed consolidation to effectively overcome these shortcomings.
To achieve both delayed consolidation and agglomeration properties, a study involved coating proppants with a resin mixture comprised of a curable resin, a tackifier polymer, and a catalyst (when needed) before blending the coated proppant grains into a fracturing fluid. After the coated proppant was packed in place, consolidation levels were observed to increase as a function of time and temperature. Mixing ratios between resin and tackifier components of this new resin system are adjustable to achieve the designed coating performance (e.g., high consolidation strength with low tackiness, or vice versa). Catalyst addition controls cure kinetics to obtain consolidation for the proppant pack, when necessary. Combining the delayed consolidation and agglomeration properties into a single proppant coating provides the ability to immobilize the proppant and also mitigate formation sand and fines migration to greatly enhance and sustain proppant pack conductivity.
Potential applications for field treatments using this resin system are discussed. In multistage fracturing treatments, the delayed curing resin allows a more flexible schedule so that drilling/milling techniques are not required to retrieve the consolidated proppant left inside the wellbore between fracturing stages. With respect to frac-pack type treatments, delayed consolidation also allows effective removal of excess coated proppant by reversing out after its placement into the fractures and screen-casing annulus packing is complete.
A New Generation of Efficient Fracturing Fluids for High Total Dissolved Solids Applications
Authors: Monreal Gabriel H. , N'Guessan Stephen O. , McElfresh Paul 
Published: June 2014

Abstract
As the stimulation of unconventional resources grows, there is a need for the development of alternative fracturing fluids that offer advantages over traditional guar-based fluid systems, particularly with regards to proppant pack clean up and minimization of potential damage to the formation. As such, key parameters that would make a fluid system a preferable option over guar are the reduction of polymer necessary to achieve desired fluid stability, as well as the ability to perform in diversified water sources such as produced water. In order to meet this demand, a low pH fracturing fluid system which uses a low residue polymer as the gelling agent has been developed.
The new fluid system is designed to accommodate the needs of hybrid fracturing designs, and uses water sources encountered on many locations. A linear gelling agent is selected that provides rapid hydration rates with water up to 110,000 mg/L total dissolved solids (TDS). Rapid hydration occurs at pH range of 5 to 11, eliminating the necessity for hydration buffers. The crosslinked system offers effective fluid stability at pH 5 with a temperature range of 125 to 250 °F, reduced polymer loadings as low as 12 lbm/Mgal, and is stable in produced water of 110,000 mg/L TDS up to 150°F. Linear gel systems also offer hydration rates of less than 3 minutes at 40°F in 2% KCl brine. This offers the advantage of minimizing the use of fresh water while maintaining a high level of performance. This paper discusses the distinct technical and operational advantages of this fluid system versus guar in various water sources, including produced water mixtures. In addition, data will is discussed which indicates its impact on productivity and formation compatibility relative to currently used fluid systems.
Remediation of Long-Term Production Deferrals from Formation Damage in a Depleted Transylvanian Sandstone Reservoir
Authors: Cavallaro Brandon , Stefanescu Dan Paul , Fava Guido Nario 
Published: June 2014

Abstract
The work completed was a comprehensive approach of understanding and treating formation damage to further redevelop a mature asset through successful remediation operations. The identification of skin was completed with slickline techniques and reservoir and production flow profile monitoring. Primary formation damage mechanisms were naturally occurring scales in the near wellbore, damage caused by water blockages and workover fluids. Redesigned completion fluids, acid pumping and innovative coiled tubing tools were used in the remediation works which were all firsts in the basin. A modified decline curve analysis technique was used to economically justify treatment of nearly all wells in the field and led to substantial production increases.
In 2003, an Association was formed to manage a mature Romanian gas field producing since 1970. Production skin was evident and in 2010 a well failed due to halite formation. Consequently, liquid and solid sampling tools were deployed within suspect wellbores. In 2010, a new workover fluid formulation was introduced but despite improvements formation damage was still induced. From 2010 to 2013, there had been an increased focus on understanding and treating calcite, halite and water block damages to boost field-wide productivity.
Formation damage was observed as being both naturally occurring and induced in the field. An initial assessment and pilot treatment of 10% of the wells led to a near 40% incremental gain in those wells. After which, the campaigns were further expanded to over 75% of the field. Technically, the investigation into formation damage changed the development plan for the field going forward. Operationally, the intervention procedures introduced were new to the basin and have been adopted by the Association's partners in other assets.
A major limit on ultimate recovery from depleted hydrocarbon reservoirs is declining well productivity. Salt formation, scale deposition, and water blockage restricts flow, reducing production rates and ultimate recovery of reserves. Therefore, economic formation damage management is an essential tool for extending field life, increasing profitability, and improving recovery of aging assets. Impressive results led to a strategic shift in local field production management and the techniques are useful worldwide in similar fields.