bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delayed Crosslink Polymer Flowing Gel System for Water Shutoff in Conventional and Unconventional Oil and Gas Reservoirs
Authors: Jayakumar Swathika , Lane Robert H. 
Published: June 2014

Abstract
A new polymer based gel system has been developed to address the excessive water production problem in fractured unconventional gas wells. Currently available polymer based water shut-off agents are unsuitable for treating high temperature hydraulically-fractured tight gas and shale reservoirs, where some fractures connect to water rich zones. The new gel developed is a low-concentration, low-viscosity delayed-crosslink polymeric gel system and is a significant improvement over traditional flowing gels used for fracture water shutoff in conventional reservoirs. The gel uses high molecular weight hydrolyzed polyacrylamide (HPAM) at low concentrations with a delayed organic crosslinker that is more environmentally benign, provides much longer gelation time (up to several days at temperatures well above 100 °C) and stronger final gels than comparable polymer loadings with chromium carboxylate crosslinkers. Results indicate that gelant with a few tens of centipoise viscosity can have gelation delayed to 12 hours or longer at temperatures of 100 °C and higher. Gels prepared with 4000 to 7000 ppm of HPAM and Polyethylenimine (PEI) were significantly stronger than those prepared with the Chromium(III) Acetate crosslinker for the same HPAM concentrations. This new gel system allows low-pressure extrusion of gelant into narrow-aperture fractures. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped with low pressures due to low concentration of polymer and delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay water loading and subsequent premature abandonment (or installation of expensive equipment), thereby extending life and reserves of unconventional gas wells. Potential applications include the Barnett Shale, where 15 percent of wells produce more water than injected during drilling and stimulation, presumably due to hydraulic fracture growth into underlying water zones.
An Investigation of Sand Retention Testing With a View To Developing Better Guidelines for Screen Selection
Authors: Ballard Tracey , Beare Steve 
Published: June 2014

Abstract
Sand screens for specific applications are often selected by reference to the results obtained from laboratory sand retention testing. Some recent publications have highlighted the problems of running some types of sand retention tests (slurry tests) at high flow rates, such that the differences between wire wraps screens and metal mesh screens may be exaggerated. With these in mind and also to address some general concerns of the authors ways to reduce flow rates in laboratory slurry tests to more realistic levels have been investigated. This has created some unforeseen effects which are discussed; video has proved invaluable in understanding these unforeseen effects. In addition, an attempt has been made to better define plugging within sand retention tests by relating the pressure build-up gradient from slurry tests to characteristics of the sand itself. Although the pressure gradient generally correlates to certain sand size and sorting parameters the spread in data suggests another factor is important. The purpose of this work is to try and better define the differences in performance between different screen designs, primarily wire wrap and metal mesh screens, in order to better define their application envelopes in terms of sand quality and hence develop more definitive guidelines for screen selection.
Effect of Coreflood Test Methodology on Appropriate Simulation of Field Treatments
Authors: Graham G. M. , Kidd S. , Stalker R. , Wright R. 
Published: June 2014

Abstract
Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. Comparative returns are often used to select the chemical for field treatments. However, significant discrepancies can arise between core and field in particular due to test methodology.
Here we describe advances over previous work when we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. It was shown that many of the limitations can be overcome through appropriate simulation techniques (see SPE 131131).
Here, we present the results of laboratory core flood tests designed to examine the effect of core flood test methodology on the derived return isotherm. This work clearly identifies certain test artefacts, in particular inhibitor oversaturation, which can impact simulation from core to field, and presents supportive core flood data with respect to the modelled isotherms. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.
Perforated Completion Optimization Using a New, Enhanced and Integrated Perforating Job Design Tool
Authors: Zhan Lang , Doornbosch Fokko , Martin Andy , Harvey Jeremy , Grove Brenden 
Published: June 2014

Abstract
Optimizing the performance of a perforated completion requires reliably estimating two groups of parameters: (a) perforation tunnel geometry, particularly depth of penetration (DoP); (b) the condition of perforation tunnels (fill and crushed zone damage). A recent industry survey showed that existing DoP algorithms, which were all based on conversion of surface concrete results to downhole stressed rock penetrations, have shortcomings. Most of the surveyed perforating design tools substantially overestimate stressed rock DoP. In addition, a vast and growing amount of laboratory and field data is revealing that the post-perforation tunnel damage primarily depends on dynamic rather than static underbalance condition. Yet the industry still lacks a reliable and practical algorithm to estimate post-perforation tunnel damage for dynamic underbalance (DUB) perforating. Furthermore, existing perforating design tools usually do not handle multi-zone completions or variations of formation properties along the wellbore.
This paper describes a perforating job design process and software tool that seamlessly integrates a newly developed DoP model, a simple but robust algorithm to calculate post-perforation tunnel damage for dynamic underbalanced perforating, and a reliable model to reflect 3D fluid flow around the perforations. The new DoP model was constructed exclusively based on rigorous laboratory tests for each individual charge in different rocks under downhole conditions, rather than converted from surface concrete results. The transient pressure properties from a comprehensive wellbore dynamics simulator can be loaded into the planning tool for perforation tunnel damage estimation. The perforation skin algorithm due to DUB was developed through a combination of extensive flow tests, conducted in state-of-the-art facilities, and 3D numerical simulations. The integrated perforating design tool provides zonal productivity estimations for single or multi-zone settings. It also introduces an option to compute perforating parameters (penetration and perforation skin) along the borehole with variable formation properties obtained from well log data. The streamlined design workflow and integrated environment allows users to optimize perforating jobs with minimum efforts. The paper includes two field examples that demonstrate the software applications.
Burst and Collapse Responses of Production Casing in Thermal Applications
Authors: Dall'Acqua D. , Hodder M. , Kaiser T. M. 
Published: June 2014

Abstract
API design equations describing casing burst and collapse limits do not address pipe body response when axial stress in the casing exceeds the material yield strength. However, casing yielding commonly occurs in thermal operations in Western Canada, where SAGD and CSS operating temperatures generally range from 200°C to 350 °C. Cemented production casing is subject to both passive and active loading conditions during operation: thermally-induced strain-based cyclic axial loading occurs in conjunction with net internal or external differential pressure. A sound engineering basis for selecting tubular configurations that considers the combined loading state in this situation and establishes an appropriate design margin does not currently exist.
This paper describes numerical analyses for combined post-yield loading conditions and provides a starting point for burst and collapse design for thermal casing. Burst analysis of axially constrained casing indicates that, contrary to what might be inferred from elastic strength calculations, an initial thermally-induced axial compressive strain does not substantially reduce the burst (rupture) pressure. By contrast, even low net external pressures can lead to ovalization and loss of wellbore access when combined with thermally-induced axial strain if the cement sheath does not offer adequate radial support. Sensitivity studies demonstrate the strong influence of pipe D/t and pressure ratios and pipe material mechanical properties on ovalization response. Analysis results are compared to API burst and collapse predictions, thermal operating experience at Shell Canada’s Peace River project, and available physical testing results for similar loading conditions.
Reaction Rate of Emulsified Acids and Dolomite
Authors: Sayed M. A. , Nasr-El-Din H. A. 
Published: June 2014

Abstract
Acid-in-diesel emulsified acid has been used in the oilfield for many years. Emulsified acid systems are retarded systems that can be used effectively in stimulation of carbonate reservoirs. Emulsified acids have primarily been used in acid fracturing and matrix acidizing. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. To predict the penetration depth of wormholes or the length obtained from an acid fracturing treatment, diffusion coefficient values need to be estimated.
This paper discusses the rheology, and reaction kinetics of emulsified acids formulated using a new emulsifier. The emulsified acid systems were prepared at 15 wt% HCl and 0.7 acid volume fraction. Emulsifier concentration was varied from 0.5 to 2.0 vol%. For all emulsions, viscosity was measured using an HPHT rheometer. Emulsified acid reaction rates, and hence acid diffusivity, were measured using a rotating disk apparatus at a temperature of 230 °F. Disk rotational speeds were varied from 100 to 1,500 rev/min. Samples of the reacted acid, from the reactor, were collected and analyzed using the Inductively Coupled Plasma, to measure calcium and magnesium concentrations.
Rheological measurements indicated that emulsified acid systems behaved as a non-Newtonian shear-thinning fluid, and this behavior can be represented by a power law model. The emulsifier concentration and temperature affect greatly the viscosity of emulsified acids. The new emulsified acid systems achieved low reaction and diffusion rates; as the emulsifier concentration increased, both reaction and diffusion rates decreased. Emulsified acid –dolomite reaction was mass transfer limited at low emulsifier concentration. The behavior was in the middle region between mass transfer limited and surface reaction limited for higher emulsifier concentrations. At high emulsifier concentration, the reaction appears to be surface reaction limited. These results can be used to optimize the design of carbonate acidizing treatments using emulsified acid.
The Impact of Annular Flows on High Rate Completions
Authors: Greene R. , Moen T. 
Published: June 2014

Abstract
This paper discusses a study into the effects of annular flow in standalone screen completions. Conventional stand alone screen designs do not constrain flow to within the basepipe. Flow is able to enter the toe of any joint and travel along the annulus before entering again at the heel section of the joint. The paper discusses the use of computation fluid dynamics (CFD) modelling carried out to illustrate the significance of the annular component on the flow and how this will affect annular solids transport and subsequently the erosion and lifetime performance of conventional screens.
This work is particularly significant in high rate gas completions. The conventional approach in the industry when using stand alone screens in gas wells is to maximize the flow area from annulus to basepipe by utilising the highest possible basepipe perforation density. This paper illustrates the fallacy in using this conventional approach and how this will significantly increase the potential for erosion.
The paper will show that the use of conventional standalone screens, and also conventional inflow control device (ICD) screens will result in a significantly high potential for erosion in the screens. This paper will propose an alternative screen philosophy for standalone screen completions in high rate gas wells, and illustrate how this philosophy will be an improvement on the current approach.
Assessing Formation Damage from Migratory Clays in Moderate Permeability Formations
Authors: Howard Paul R. , Hinkel Jerald J. , Moniaga Nita C. 
Published: June 2014

Abstract
As new reservoirs are developed and formations are exposed to various fluids, clay swelling and fines migration can cause serious damage. Clay stabilizers are generally added to mitigate these problems. However, the performance of formation stabilizers is not always properly assessed in the traditional analyses of formation samples. In general, laboratory testing with formation material is performed to define the best additive and concentration. Incorrect choice of stabilizer additives can result in severe damage from swelling and mobile formation clays. There appears to be no standard method for conducting formation stabilizer evaluations, therefore, it is difficult to make meaningful comparisons. Test methods based on the capillary suction time (CST) test or hot rolling lack any theoretical basis and may not show subtle effects.
A new test protocol incorporates several significant improvements over the traditional core flow methods. It considers important factors such as the critical salt concentration and the critical flow velocity. A key improvement is that the proposed method closely mimics pumping and cleanup operations actually encountered in field operations. The new test method is able to distinguish performance differences based upon both stabilizer chemistry and concentration.
Testing results from a moderately sensitive Berea core yielded a surprising finding: well-known organic stabilizers were only slightly more effective than de-ionized water, whereas inorganic salts were quite effective, even at low concentrations. Further, confirming findings by others, our results showed that the Berea core used in this study required no stabilization at 270°F.
Numerical Simulation of the Acidizing Process and PVBT Extraction Methodology Including Porosity/Permeability and Mineralogy Heterogeneity
Authors: de Oliveira T. J. , Melo A. R. , Oliveira J. A. , Pereira A. Z. 
Published: June 2014

Abstract
This work presents the development of a methodology to numerically represent the acid treatment in a test plug, as well as to reproduce the different existing dissolution patterns and to obtain the corresponding values of pore volumes to breakthrough (PVBT). The numerical simulation is performed in a commercial CFD package that uses finite volume method. The modeling includes the effect of heterogeneous porosity/permeability and the presence of different types of minerals that impact the PVBT value, since they have different reaction rates at usual operation temperatures. Through these considerations, the formation of preferential channels, which are characteristics of the various patterns of wormhole, is captured by the numerical simulation.
The goal of this development is the extraction of the characteristic PVBT curves for any pair formation/acid by numerical simulation. It is possible through the use of measured data during drilling, such as average porosity and range of variation, rock mineralogy, etc., and through the knowledge of reaction rates for each pair formation/acid. Using these data, the simulation is able to extract PVBT curves for different numerical test plugs, making it possible to prepare a statistical analysis that has greater significance than just a few experimental tests.
The results show that PVBT curves obtained numerically are in good agreement with the physical behavior expected when compared to experiments. The variation range of the heterogeneous porosity and the presence of different minerals, which have distinct reactivity with acid, significantly change the behavior of the process for the same operating condition.
Better understanding of acid treatment in carbonates (both limestone and dolomite) is important since the new Brazilian petroleum reservoirs are located below pre-salt layer. These rock formations are commonly subjected to acid stimulation in order to increase reservoir productivity. Therefore, the numerical PVBT curves obtained from this work could be used in simpler models to simulate the acid treatment in a reservoir scale. The use of more accurate curves can help the engineers to improve the design of operation conditions and, thus, increase the production capacity and distribute uniformly the treatment.
Customizing Drill-In Fluid for Peregrino Project in Brazil: Laboratory Development and Field Experience
Authors: Han Liqun , Clinch Duncan , van der Zwaag Claas , Galletti Eduardo , Fornasier Frank , Estevez Fabian , McMillan Nelson , Green Justin , Patey Ian 
Published: June 2014

Abstract
This paper describes the design and qualification process used to select a reservoir drill-in fluid (RDF) for the Peregrino field offshore Brazil, and the successful application of this fluid.
The Peregrino field is located east of Rio de Janeiro in the southwest Campos Basin area. Approximately 2.3 billion barrels of oil are in place in the Peregrino reservoir. The productive sands in this variable reservoir typically exhibit permeabilities between 6 and 15 Darcy, and are unconsolidated with interbedded shales. Peregrino crude oil is heavy (13API) and viscous. The estimated recoverable volume of crude oil is 300 million to 600 million barrels.
The selected fluid, a NaCl brine-weighted water-based mud employing KCl and Glycol additions for shale stabilization, was used to drill the first wells at Peregrino. Penetration rates were high and zero non-productive time occurred. To achieve this drilling performance in the high permeability, unconsolidated, heavy oil reservoir, an extensive fluid selection process was performed to optimize the drill in fluid for maximum well productivity. Key test results reviewed in this paper include: Bridging solids optimization, lubrication, shale inhibition, fluids compatibility, filtercake lift off and backflow performance, breaker fluids and formation damage
The reservoir sections of the wells were successfully drilled, open-hole-completed with sand screens and gravel packed with 100% efficiency.
Prediction of Injection Induced Formation Shear
Authors: Han H. , Khan S. , Ansari S. , Khosravi N. 
Published: June 2014

Abstract
Formation integrity is a critical confinement factor in any injection process such as waste injection, CO2 capture and storage, and thermal/pressure injection in oilfields. Rock can fail in tensile, shear or in combination of complex modes. In situ stresses variation caused by injection may shear the caprock posing continued risk of containment breach. We developed an integrated approach to predict the alteration of in situ stresses and shear failure potential by combining data from sonic logs, image logs, mini-frac test data, formation pressure measurement, and rock mechanical core test data. In this approach, three-dimensional Mechanical Earth Models containing the reservoir, overburden, under-burden and side-burden were constructed. Coupled simulations were then run between dynamic reservoir model and geomechanical model to quantify stresses change induced by injection. The resulted formation shear and surface heave will then be calculated regarding the location and timing of occurrence during the planed injection operations.
The methodology has been applied to several steam injection case studies in Northern Alberta oil sands area, Canada. Our analysis indicated that three years of steam injection would cause up to 2 MPa stresses contrast; formation shear failure was forecasted to occur earlier than formation tensile failure at a same time step; the calculated surface heave due to steam injection was around three 3 cm. The simulation results enabled the optimization of injection scheme and proactive monitoring plans to avoid catastrophic events.
The Application of Nanoparticle Dispersions to Remove Paraffin and Polymer Filter Cake Damage
Authors: Mcelfresh P. , Olguin C. , Ector D. 
Published: June 2014

Abstract
The use of stabilized nanoparticle dispersions (NPDs) containing silica particles between 4-20 nm in diameter have been shown to be effective at removing skin damage associated with paraffin blocks, as well as polymer based treating and stimulation fluids. The arrangement of particles at the three phase interface into structural arrays promotes lifting of the damage from the surface, stimulating the reservoir. Aqueous dispersions of nanoparticles used in conjunction with traditional remedial methods can effectively remove damage near the wellbore to be produced out of the well, instead of dissolution and potential displacement of the damage further into the formation.
Many of the declining oil fields around the world owe a significant portion of their decreased production to formation damage. Usually, this damage is indicative of naturally occurring blocks, like paraffin, or as a result of intervention processes that occur over the lifetime of a well during drilling, stimulation, or intermittent remediation treatments. Eventually, the well can become damaged to the point it is no longer economically viable.
This paper will show lab and field results that indicate aqueous nanoparticle dispersions are a capable, and efficient additive for stimulating a damaged well by removal of skin from the surface of reservoir rock. This effect is due to a unique force called disjoining pressure, which causes particles at the nanometer-scale to force themselves between organic matter and the substrate at the interface of the treating fluid. This force promotes the separation of an organic phase from a rock surface.