bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of Environmentally Friendly Chelating Agents for Applications in the Oil and Gas Industry
Authors: de Wolf C. A. , Bang E. , Bouwman A. , Braun W. , De Oliveira E. , Nasr.El-Din H.
Published: June 2014

For many decades, chelating agents have been used successfully as an additive in the oil and gas industry, for example during scale removal, iron control and matrix stimulation. More recently, these chemicals have also been used as standalone fluids for the same applications. However, the traditional chelating agents like ethylene diamine tetraacetic acid (EDTA), hydroxyethyl ethylene diamine triacetic acid (HEDTA) and nitrilo triacetic acid (NTA) suffer from slow biodegradability and/or an unfavorable health profile. To better meet the stricter health, safety and environmental requirements of the regulatory bodies and the industry, new environmentally friendly chelating agents have been introduced. The question is whether these new chelating agents have the required properties for a versatile downhole application.

This paper compares four commercially available, readily biodegradable amino polycarboxylic acid type chelating agents, including glutamic acid N,N-diacetic acid (GLDA), aspartic acid N,N-diacetic acid (ASDA), methyl glycine diacetic acid (MGDA) and ethanoldiglycine (EDG) on a number of properties relevant for the oil and gas industry. It covers the solubility as a function of pH and in various acids, thermal stability, iron control, corrosion tests with low-carbon steel and Cr-based alloys and coreflood experiments on both carbonate and sandstone cores. The corrosion and coreflood experiments were conducted under realistic temperature and pressure conditions.

Although the structural resemblance of the tested chelates is great, the results proof that even the slightest change in the chemical structure can have a significant impact on the properties and hence the use in the oil and gas industry. Furthermore, the results show that the new generation of chelating agents include candidates that have a lot more to offer than the traditional chelates in terms of corrosion, functionality in matrix acidizing jobs, descaling, impact on tubular, completion and environment. Our studies show that GLDA is the most versatile environmentally friendly chelating agent.
Complex Completion Design and Inflow Prediction Enabled by Detailed Numerical Well Modeling
Authors: Byrne Michael , Djayapertapa Lesmana , Watson Ken , Goodin Barry
Published: June 2014

An Operator was unable to model a potential new (additional) completion of a 330 m cased hole perforated sand screen and ICDs interval in a mature high water cut well which was originally completed with a 916 m open hole stand alone sand screen and Inflow Control Devices (ICDs) section in a multidarcy sand.

The potential opportunity to perforate this 330 m section presented significant potential reservoir drainage upside but could not be modelled using conventional well inflow prediction or reservoir simulation techniques. In order to determine if the recompletion was economically viable, the operator required a way to model the recompletion and the existing completion to determine the overall completion performance.

The complexity of the original open hole section completed with sand screens and ICDs and the new target to be completed with perforations, sand screens and ICDs was solved using computational fluid dynamics (CFD) modelling and high performance computing.

The existing and new reservoir intervals are characterised by unconsolidated high permeability sands. The reservoir conditions mobility ratio of oil to water is approximately 30:1. Due to high total liquid production rates, the existing open hole completion is producing at well above the economic oil rate cut off despite being at approximately 95% water cut and therefore the existing completion interval cannot be abandoned. The new recompletion perforation interval would initially produce at 100% oil. The key question was, what will the new recompletion interval add (if anything) to the overall well production rates and is the new recompletion economically viable. Conventional analytical or even 1D or 2D numerical models simply cannot handle the complexity of the geometry of this well's open and potential cased hole intervals, perforated intervals, sand screens and ICDs.

A 3D fully coupled well model was constructed and 2 phase CFD modelling undertaken in a combined model size of over 500 million cells each with unique properties. Through employment of what is thought to be the most comprehensive inflow model ever built, the contribution from the original open hole interval and the new interval were estimated and the optimum completion design investigated allowing the operator to determine the economic viability of the recompletion.
Materials Science Improves Silica Sand Strength
Authors: Bestaoui-Spurr Naima
Published: June 2014

Due to its low cost, availability, roundness and strength, silica sand has been the preferred proppant for hydraulic fracturing. However in deeper completions stronger proppant must be used. If the strength of the material does not match the formation closure stress conditions, it will crush and fines will be generated, often leading to significant proppant pack conductivity damage. As formation closure stress increases, materials that can withstand stronger stresses than silica sand, such as resin-coated sands and ceramic proppants, must be used. Resin-coated silica proppant can be used up to about 8,000 psi closure stress, improving fracture treatment results; ceramics made of aluminosilicates ores are much stronger and provide better conductivity for formation closures of over 12,000 psi. However ceramic proppants cost significantly more than silica proppant and have higher densities that require higher fracturing fluid flow rates and fluid viscosity for adequate transport and placement into the fractures.

In the present work inorganic polymers were used as coatings to prepare silica proppant with superior strength properties. The physical properties of these inorganic polymers are largely determined by their composition. They are made of a solid inorganic network having an amorphous three-dimensional structure that significantly increased silica proppant compressive strength. The resulting coated proppant materials show an excellent tolerance to high closure stresses (over 10,000 psi) while their apparent specific gravities are slightly lower than sand (2.55 to 2.59 g/cm3). Imaging studies show very homogeneous, well-distributed layers around the sand particles, suggesting a successful coating process.
The Water Blockage Effect on Desiccated Tight Gas Reservoir
Authors: Assiri Wisam , Miskimins Jennifer L.
Published: June 2014

Increasing world demand on energy has encouraged the development of natural gas resources from a variety of sources. Tight gas is a major gas resource which accounts for 14% of the total gas resources in the world, including conventional systems (Total, 2012). Water blockage is considered a potential damage issue in tight gas reservoirs and motivated the initiation of this study.

A tight gas reservoir is a low permeability reservoir of less than 0.5 md which tends to have higher capillary pressure and higher irreducible water saturation than a conventional reservoir. Tight gas reservoirs also have smaller grains which signify the effect of water film around the grains on gas flow. The gas relative permeability in tight gas formations becomes more sensitive to liquid saturation due to the nature of its grains. As some of these reservoirs show conventional-like connate water saturation, this led to a hypothesis that these reservoirs have gone through a desiccating process and reduced the connate water saturation to a lower value than the irreducible value.

The objective of this study is to examine if water blockage is a potential issue by generating relative permeability curves and simulating different production cases with different water saturation settings. By looking at the well performance and water and gas recovery in these situations, a new understanding of tight gas performance is achieved. The method used included creating a simulated generic model and setting the water saturations at different settings to see the effect of injecting water during drilling and hydraulic fracturing. Two cases with open flow and fixed downhole pressure were discussed this paper.

The results show an effect on gas production by delaying production by 21 years in the open flow situation. The gas production is reduced up to 17.17% in the open flow mode. In addition, cases with different water saturation settings never recovered all of the injected water, and in fact, the degree of recovery is proportional to the degree of desiccation.
Engineered Approach to Isolate Intervals Invaded by Water or Gas in Naturally Fractured Carbonate Formations
Authors: López J. , Martínez Ballesteros A. , Miranda R. , García C. , Deolarte C. , Vidick B. , Girón Rojas R. , Millán A. , Rivas J. G. , López A. , Miquilena E.
Published: June 2014

An excessive water cut or high gas/oil ratio in a production interval presents a major concern in sustaining oil production, often requiring fast and efficient workover solutions to enhance the oil recovery process. Wells in the Cantarell field, a mature depleted field in the Bay of Campeche in the Gulf of Mexico, are facing drastic decreases in their production and, depending on producing zone, an increase in either water cut or gas/oil ratio. Other developed fields in Mexico's Region Marina, such as the Ku-Maloob-Zaap, have constantly increased their hydrocarbon production through the years with an incipient increase in water and gas increments.

The high water cut and gas increments have had a strong impact on the production strategy, opening the opportunity for application of non-conventional, innovative, and engineered solutions to isolate or abandon production intervals invaded by gas or water and continue production from upper or deeper zones. The pay zones consist of naturally fractured, vugular carbonates with permeability as high as 5 Darcies, from Paleocene, Cretaceous, and Jurassic formations. Their characteristics present the following challenges that need to be overcome to succesfully achieve the required isolation:

Loss of fluid circulation, which is necessary for well control and also negatively affects the fluid placement in the workover jobs. High gas presence, gas cap driven, which is a major concern on surface. Lack of primary zonal isolation, resulting in migration of water or gas to the productive intervals.

This paper summarizes the non-conventional technologies and techniques applied to isolate the water and gas producing intervals and their synergistic performance: reticulated gel, lost circulation fiber tecnologies and gas-tight slurries integrated in an engineered solution. Results from field cases demonstrate the design, execution, and evaluation of these applications.
Optimizing Sandstone Matrix Stimulation in HT Well ‘X’ (A Case Study)
Authors: Hassan S. S. , Nadeem A. , Bregar U. B.
Published: June 2014

Pakistan's demand for natural gas is quickly outstripping supply and the crisis is a symptom of a much larger problem destined to cause consumers even greater pain in the future. In this picture every MMscf of gas is not only important for the country but also important for OMV, which is fueling Pakistan for more than 20 years. OMV is trying hard to meet the demand by restraining the decline in currently producing fields and to develop unconventional resources. In one of OMV operated fields, after watering out 3 wells, well ‘X’ was the only one available to feed 13 MMscf gas per day to processing plant to keep it alive. To increase the recovery from reservoir, well ‘X’ was put on wellhead compression in March 2012 subsequently rapid decline rate (1.09 MMscf/month) was observed; finally production drop to 7.8 MMscfd which was alarming to shut down the complete plant below 6 MMscfd.

The production modeling using commercial package depicted the skin of +16 in well ‘X’ which was not supported by available hard data. The interpretation of last buildup data was not strengthening the idea of near wellbore damage, further the reservoir pressure used was dubious as it was taken ~1 year ago. Two cores were available in well ‘X’; unfortunately none was from sandstone producing interval. As an analogy two core plugs from nearby well were sent for XRD analysis & core flow test was performed with specially designed organic clay acid for high temperature reservoirs (OCA-HT). Based on encouraging core flow test outcomes, an optimum job volume was engineered considering the critical zones radius (up to 1 ft), in fear for fine migration & water producing zone. Matrix stimulation job was executed in October 2012 which resulted in increment of ~7 MMscfd extending the plant life beyond 1 year.

This paper describes the complete case study of optimizing the matrix stimulation in high temperature sandstones. Furthermore it will show how results achieved so far are promising which added a reasonable value to the producing asset and saved huge revenue loss to the company.
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

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

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

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

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

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

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

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

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

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

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

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.
The First Visualization of Acid Treatments on Carbonates With 3D Nuclear Magnetic Resonance Imaging (NMRI)
Authors: Krebs M. , Lungwitz B. , Souza A. , Pépin A. , Montoya S. , Schlicht P. , Boyd A. , Vidoto E. , Polli R. , Bonagamba T.
Published: June 2014

Carbonate reservoirs with their high hydrocarbon potential show often a great heterogeneity in their inner rock structure, wherefore stimulation treatments are often necessary to maintain or establish fluid production. Therefore, core flow tests are usually conducted to test and model stimulation treatments within a laboratory scale in order to predict their performance. The visualization of wormholes that were created within core flow tests requires novel technologies for evaluation and pathway prediction purposes. Unfortunately, past visualization techniques were always associated with the destruction of the core sample and in that way, an increased demand raised in non-destructive methods.

Nuclear Magnetic Resonance Imaging (NMRI) is such a method that fulfills the approach of being non-destructive. The technology is widely known by medical applications, but has never been used before in correlation with 3D rock imaging. Hence, this study developed a procedure on how to use the NMRI technology to visualize wormholes with NMRI in 3D.

Therefore, a comprehensive study was started by initially choosing and obtaining various core samples that have different contents of calcite and dolomite. These core samples were imaged with the NMRI and μCT technology in their unchanged state as well as basic petrophysical experiments were conducted for initial experiments. The μCT technology was utilized as reference visualization technique, since it provides a very high resolution with a corresponding high level of detail. Afterwards, core flow tests were conducted on the core samples with various acid systems and wormholes generated. Finally, the core samples with wormholes were imaged again with the NMRI and μCT technology, whereby the NMRI acquisition technique was improved towards imaging of rock samples and the results were compared to the μCT results. The NMRI results showed moderate imaging achievements for the unchanged rock samples and high quality imaging achievements for the extracted wormholes.
Multizone Openhole Stand Alone Screen: Innovative Sand Control Solution to Develop Shallow Gas Reservoirs in the Mahakam Delta
Authors: Laidlaw D. , Muryanto B. , Isdianto-Maharanoe M. , Alberson-Panjaitan R.
Published: June 2014

Developing shallow reservoirs in the Mahakam Delta requires cost effective completion solutions to produce gas from multi-layered, unconsolidated sands. Typically, multi zone gravel pack systems have been utilised as the sand control completion methodology. Technical limitations of these techniques in terms of zone spacing, number of zones and well deviations drove the need to develop an alternative completion technique. Using modified existing screen and open-hole isolation technology, a unique open hole stand alone screen (SAS) system was developed.

Several challenges must be overcome in the Mahakam Delta reservoirs. Highly unstable and inter-bedded coals seams that swell and slough create challenges in terms of both running the completion equipment and its effective performance once installed. Water bearing sands underlay the productive sands making water breakthrough a risk.

To date, four wells have been completed with the SAS system. Overall productivity has exceeded expectations and most importantly, the sand screens have provided excellent sand control with no sand production occurring. Cost savings have been achieved through reduced completion times, eliminating pumping operations and reducing surface locations. Successful pilot wells will lead to further development of shallow reservoirs previously deemed uneconomic due to the marginal nature of the Tunu Shallow reserves.
A Simplified Methodology for Dynamic Drilling Fluid Filtration Estimation Considering Mudcake Compressibility
Authors: Calcada L. A. , Scheid C. M. , Calabrez N. D. , Waldmann A.T.A. , Martins A. L.
Published: June 2014

Fluid filtration and invasion occur in drilling oil wells operations in overbalanced conditions. In static and dynamic condition, the buildup of a porous and compressible cake on the wall of the well avoids the inadequate invasion and possible damage to the reservoir. The composition of the drilling fluid and operational conditions affect the mud cake build up and its properties as permeability, porosity and compressibility. Consequently, these parameters are important in the determination of the filtrate and fluid invasion. The main objective of this work was to evaluate the filtrate parameters and propose a simplified model and methodology to simulate that process. In this study, both real drilling fluids and fluids prepared in laboratory were considered. The experiments for parameter evaluation were conducted in a filtration cell HTHP (high temperature / high pressure) using filter paper as filter medium. The simplified methodology and model presented hereby are useful in the estimation of the amount of filtrate and the invasion of the drilling fluids in the process of drilling of oil wells. The mathematical model for filtration and fluid invasion calculation was based in mass and momentum conservation equations and hydraulic equations. Based on the experimental data and mathematical model, mud cake parameters were determined, such as permeability, porosity, compressibility, thickness and friction factor. The simulations results showed a good agreement between field and simulated data. Combining the proposed simplified model/methodology and the mud cake and the reservoir rocks properties, it was possible to simulate and to estimate the filtration and fluid invasion in different conditions that allows optimum design of bridging agents for drill-in fluids.
Critical Sand Deposition Velocity in Horizontal Stratified Flow
Authors: Ibarra Roberto , Mohan Ram S. , Shoham Ovadia
Published: June 2014

Transport of sand in multiphase pipelines occurs in the petroleum industry as sand is produced co-mingled with crude oil. Stationary sand beds are formed at the pipe bottom when the flow velocity is lower than the critical sand deposition velocity. These sand beds reduce reservoir production and affect the integrity of the pipe system due to pipeline plugging and erosion/corrosion produced by sand particles. Therefore, the production system must be designed to operate at a velocity high enough to enable transport of sand particles along the pipe. For that reason, it is crucial to predict the critical sand deposition velocity in order to maximize reservoir production.

Gas-liquid-sand flow hydrodynamics, which is commonly encountered in most reservoirs and also in oil and gas transportation pipelines, is more complex than liquid-sand flow, making the modeling extremely difficult. At present, gas-liquid-sand flow is still not well understood, with limited data available in the literature. In addition, the effect of sand concentration has not been thoroughly studied for two-phase flows transporting sand.

Experimental and theoretical investigations have been conducted in this study on gas-liquid-sand stratified flow in horizontal pipes at low sand concentrations. A 4-in experimental facility was designed and constructed and data were acquired utilizing air-water-glass beads flow. The data include measurements of critical sand deposition velocities, namely, the transition between moving and stationary beds. The data reveal that for a constant superficial liquid velocity, the critical mixture and liquid sand deposition velocities increase with increasing sand concentrations. Also, for a given sand concentration, the critical liquid velocity is almost the same for different superficial liquid velocities.

The sand deposition correlations of Oroskar and Turian (1980) for single-phase flow and Salama (2000) for two-phase flow are modified and extended in order to develop a new correlation. The developed correlation enables the prediction of critical sand deposition mixture velocity for horizontal stratified flow, as a function of sand concentration along with other parameters. Comparison between the predictions of the developed correlation and the experimental data reveal a very good agreement, whereby the relative errors of mixture and liquid critical sand deposition velocities are ±2.5% and < 5%, respectively.
Design and Successful Field Execution of Sand Control Completions in Naturally Fractured Reservoirs
Authors: Tahirov Tahir , Allam Robbie , Mason John , Twynam Allan , Tanilir Beran , Sweeney Kieran , Bissoon Anderson
Published: June 2014

The Clair Ridge field development is located in the UK Continental Shelf, 142 miles north of mainland Scotland. This is the second phase of the Clair Field Development involving a subsea pre-drilling campaign and programmed long term well suspensions prior to new platform arrival. Two pre-drilled horizontal wells have been successfully completed with downhole sand screens in a geologically challenging environment, and suspended with cleaned-up hydrocarbons across the reservoir until the wells can be tied back to the platform in 2016.

The reservoir drilling and completion design strategy was complicated due to the reservoir section being a naturally fractured sandstone alongside high permeability and weak matrix intervals susceptible to sand production. This presented several challenges to the team: the high risk of losses whilst drilling the reservoir with the probable use of large volumes of lost circulation materials (LCM), the risk of damage to the natural fractures or high permeability zones impacting subsequent well productivity, the need for down hole sand control completions, the ability to run these across a reservoir section containing large amounts of sized calcium carbonate LCM materials and also the mitigation of screen plugging from filter cake and LCM during well start-up. The downhole completion hardware was specifically designed to allow efficient placement of chemical breaker to dissolve LCM and filter cake to reduce the risk of sand screen plugging. The importance of minimising screen plugging and formation damage was also dictated by long term suspension of the pre-drilled wells required for start-up of a new offshore platform.

This paper details the reservoir sand control completion design philosophy, the drilling and completion fluid system design and assurance testing in readiness for the technical challenges to be faced and the overall operational practices used in the field execution. The well flow-back and test results exceeded expectations, indicating good flowing length, greater than predicted Productivity Index (PI) and absence of skin damage, which creates significant benefit for the Clair Ridge project.