bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acid or Propped Fracturing in Deep Carbonates? Experiments and Field Results
Authors: Oliveira T. J. , Neumann L. F. , Azevedo C. T 
Published: June 2014

Abstract
The deep and hard carbonates found offshore Brazil are being extensively evaluated, and some of them would require fracture stimulation to enable commercial development. Due to the high effective normal stresses expected during the exploitation stage of pre-salt development, acid fractures could have very low conductivity values, depending on formation mechanical properties. Since perform propped fractures is more risky, it is important to create selection criteria to know precisely the fracture technique to be used. There is no agreement in the technical community regarding the survival of an acid fracture at closure stress greater than 5,000 psi. However, the experience that leads to this controversy is mainly based on: (1) wells on land and, (2) few published tests on rocks with mechanical properties compatible with those depths.
This article aims to discuss Petrobras’ fracturing selection criteria development. The experimental data currently available for acid fracturing Brazilian deep carbonates will be presented. Laboratory test are performed to verify whether an acid induced fracture can withstand high effective normal stresses, keeping an acceptable conductivity. Key mechanical properties are measured in order to understand acid fracture conductivity behavior under stress. These mechanical properties are correlated with log data to allow the use of laboratory results on the fracture technique decision of a particular well. Field data regarding acid fractures wells will also be addressed.
GaStim Concept - A Novel Technique for Well Stimulation. Part II: From Laboratory to Field Pilot Testing
Authors: Restrepo Alejandro , Ocampo Alonso , Lopera Sergio , Coronado Jorge L. , Sanabria Rosa B. , Alzate Luis G. , Hernandez Sergio 
Published: June 2014

Abstract
The present work is the continuation of SPE 152309 "GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics" and contains further experimental work and field pilot testing stages of the GaStimulation method already proposed by the authors. Systems studied correspond to quartz-arenites containing volatile oil and retrograde gas condensates exhibiting hydrocarbon permeability impairment under depletion. In such systems, treatment penetration and adsorption are key factors for benefit sustainment. Supported by the theoretical background and preliminary lab tests presented in part I, the second stage of the GaStim project was planned and executed covering the testing of additional chemistries, pilot well candidate selection and execution and results evaluation. Three field pilots are reported; A first one of induced water removal after frac by stand-alone gas injection; the second, where gas + chemical dispersion is injected to reach a condensate damage radius beyond 200 ft and a third one, corresponding to a volatile oil system in which asphaltene damage have been partially re-established at reservoir level by gas / solvent co-injection. In the first scenario, Sw reduction / Kg improvement is attained in the gastimulated area probably by coupled effects of evaporation and water slug displacement. For the condensate blockage scenario, it was noted that micellar type of surfactants exhibit the best performance when tested against IFT reduction capacity, Kg re-establishment and liquid bank re-mobilization. In this case, it was also observed that the tuning of chemical concentrations and deployment method are key to maximize hydrocarbon flow capacity and minimize surface back flow emulsion after Gastimulation. Finally and for the third scenario, it is noted that oil declination trend is positively changed after solvent + gas co-injection from a gas injector well. Further experimental work is planned to support modelling approaches both aimed on improving design criteria and expanding the potential of the technique into more challenging environments.
Experimental Study on the Cement-Formation Bonding
Authors: Opedal Nils , Todorovic Jelena , Torsæter Malin , Vrålstad Torbjørn , Mushtaq Waqas 
Published: June 2014

Abstract
Detailed information on the quality of the cement job is vital to ensure economical, safe and stable production from a reservoir. A crucial part of this is the ability of cement to bond to the formation. Improper removal of drilling fluid or cement placement, or debonding due to unfavorable wellbore conditions can create potential flowpaths. Loss of zonal isolation from cement sheath failure can appear at three possible locations: at the cement-formation interface, in the bulk cement or at the casing-cement interface.
This experimental study focused on the cement-formation interface. The primary objective was to quantify the effect of various rock formation types on the cement-formation bonding, and the effect of altering the rock surface with various drilling fluid films before cementing. The secondary objective was to visualize the interfaces using micro-computed X-ray tomography (p-CT) and to observe any link between the measured shear bond strength and the presence of pores, cavities or films along the cement-formation interface.
The results showed that the different rock formations exhibited different interactions with the cement. However, it was also shown that the presence of drilling fluid, and drilling fluid type, were more crucial parameters for cement-formation bonding. The drilling fluid presence reduced the bonding strength, and it was shown that by using oil- or water-based drilling fluids the cement-formation bond was affected differently.
The Time-Dependent Permeability Damage Caused by Fracture Fluid
Authors: Bostrom N. , Chertov M. , Pagels M. , Willberg D. , Chertova A. , Davis M. , Zagorski W. 
Published: June 2014

Abstract
Hydraulic fracturing causes a large amount of fluid to leak off into unconventional reservoirs and the fluid is not recovered through flowback. The fluids enter the pore structure of the formation, and the presence of the invading phase blocks the in-situ phase. This event reduces permeability, particularly in unconventional reservoirs. Operators shut-in the well for an arbitrary amount of time after fracturing. The time could allow the phase blocks to dissipate, increasing permeability. Conventional core flow tests and relative permeability evaluations using centrifuge drainage tests are unreliable—if not impossible—in these ultralow-permeability unconventional rocks.
We present a method to measure the gas permeability on core plugs of mudstones at reservoir conditions, both before and periodically after the plug was exposed to fracture fluid. The change in gas permeability over time allows optimization of the shut-in time. In addition, the combined rate of leakoff and imbibition is measured while the material is exposed to fluid. At the conclusion of the test, the axial water profile is determined by measuring unconfined compressive strength using the mechanical scratch machine and water saturation with Karl Fisher titration.
Initially, the samples are saturated with gas and have the highest permeability. As the plug is then exposed to water, water imbibes into the core forming a water block. The water is removed from the face of the plug. Immediately after the core was exposed to water, the permeability drops below the detection limit. In most core tested, the water block dissipates over time increasing the permeability. Experimental results on core plugs from two major shale plays show that imbibition and fluid loss into ultralow-permeability rock can be substantial, but these processes are also highly variable. We developed a measure of the phase block dissipation. The information gives operators a quantitative measure to determine the length of shut-in periods and for the development of other methods to minimize the damage from water imbibition.
Advancing Chemical Sand and Fines Control Using Zeta Potential Altering Chemistry by Using Advanced Fluid Placement Techniques
Authors: Singh Pratyush , Ludanova Nataliya , van Petegem Ron 
Published: June 2014

Abstract
Sand and fines production is one of the oldest problems in the petroleum industry and one of the toughest to solve. Today, many sand control technologies and methods exist and in certain cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require a sand control solution until later in their lives. Chemical sand control solutions have been around for many years and have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However due to the difficulties with placement, and in many cases their association with some degree of reduction in permeability, there have been reservations regarding the use of chemical methods as a standard. This paper presents a unique chemistry that increases the maximum sand/fines free rate without a significant reduction in permeability and discusses the advanced placement techniques essential for a successful application. It includes study of two hundred and fifty wells which have been treated with zeta potential altering chemistry and presents analysis of both failed and successful applications and the lessons learned.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.