bluuebunny/crossref_metadata_2025_split huggingface dataset:
Newly Developed, Highly Automated Apparatus for Rapid Evaluation of Stimulation Fluid Additives
Authors: Recio Antonio , Benoit Denise , Potty Ajish , Sun Jianlei , Henkel Kristina 
Published: January 2018

Abstract
This paper describes the development of a highly automated apparatus and customized software package to rapidly evaluate the performance of surfactant additives in dry gas shale reservoirs. A major challenge throughout the industry is the ability to reduce water saturation resulting from fluid leakoff into the formation matrix during stimulation operations. The new method presented in this paper to help identify the optimum surfactant for reducing post-treatment water saturation based on well-specific parameters. Conventional laboratory evaluation of stimulation fluid additives typically involves coreflow studies, which are excessively time consuming and have poor reproducibility as a result of core-to-core inconsistencies. The focus of this endeavor was to develop a statistically relevant method that can use drill cuttings samples and measures surfactant additive performance data with high confidence and reproducibility for the tested formation material.
Data analysis included analysis of variance (ANOVA) followed by post-hoc Tukey honest significant difference (HSD) range testing. Test apparatus results were also corroborated with coreflow studies. Eight surfactant additives were evaluated in the presence of four different fracture fluid formulations and formation samples. For each surfactant/fracturing fluid/formation test matrix, the software was able to rank surfactants performance based on the volume of fracturing fluid displaced from a column pack normalized to the pressure gradient. No individual surfactant performed best more than 40% of the time within this test series, and the surfactant-laden formulations always statistically outperformed the nonsurfactant control. The results imply that the addition of surfactants results in increased treatment fluid load recovery. Reservoir simulations were performed to investigate the effects of increased load recovery and depth of invasion of fracturing fluids on hydrocarbon production. The simulation results confirmed the assumption that minimal invasion of treatment fluid into the matrix of the formation resulting from increased load recovery does improve hydrocarbon production. The simulation data also suggest this observed hydrocarbon production improvement is particularly prevalent in the early time/cleanup period of the life of the well.
A key feature and novelty of the apparatus is the ability to evaluate numerous surfactants in series and the potential to perform up to 24 individual tests in an 8-hour shift. The results presented in this paper showcase the utility of the newly developed apparatus, which offers a new method for rapid customization of stimulation fluids.
A Theoretical Study of the Effect of Salt Precipitation on CO2 Injectivity
Authors: Shaibu R. , Sokama-Neuyam Y. A. , Ursin J. R. 
Published: January 2018

Abstract
Adequate well injectivity is required to successfully inject large volumes of CO2 through a minimum number of wells. Brine vaporization in the wellbore vicinity has been identified as a major CO2 injectivity impairment mechanism especially in deep saline reservoirs. A bundle-of-tubes model was developed to investigate basic mechanisms of salt precipitation and to quantify injectivity loss induced by precipitated salts during CO2 injection into saline formations. A Berea sandstone rock was reconstructed with a bundle-of-tubes model. A correlation was developed to estimate the solid salt saturation in the pores based on the properties of the aqueous phase. A parameter capable of tracking the development of the dry-out zone was introduced to model the distribution of salt in the pores. A relative injectivity change index was then used to quantify injectivity impairment induced by precipitated salts. A tortuosity factor was incorporated to account for the tortuous path taken by fluids in porous media. A sensitivity study was performed to assess the effects of parameters such as brine salinity, initial permeability, injection flowrate and porosity on injectivity loss. The model can reproduce some experimental results of drying of brine-saturated sandstone cores by supercritical CO2. A sensitivity study of the parameters affecting injectivity show that; (1) salt precipitation occurs in the dry-out zone where most of the irreducible water in the trapped brine has evaporated, (2) increasing brine salinity has adverse effect on injectivity, (3) salt precipitation affects permeability more than porosity and (4) in rocks with high initial permeability, salt precipitation is minimal. These findings are important for a successful CCS project since CO2 injectivity controls essential aspects of storage which are the rate, the quantity and length of time for CO2 injection into a formation.
Investigating Impact of Rock Type and Lithology on Mud Invasion and Formation Damage
Authors: Ezeakacha C. P. , Salehi S. , Ghalambor A. , Bi H. 
Published: January 2018

Abstract
Formation damage from mud invasion is a complicated process that is influenced by mud type, downhole fluid particle size distribution (PSD), mud rheology, rock type, lithology, permeability, drill pipe rotation, geochemical factors, pressure, and temperature. Many of these variables are often ignored, simplified, or underestimated. Thus, their individual and combined effects on formation damage is not well understood. Among these factors, the porous media complexities play a key role in determining the extent of drilling mud damage to the formation.
This paper is focused on characterizing water based mud's (WBM) invasion and damage to different rock cores representing various lithologies, under simulated dynamic wellbore condition. The experiments performed in this study were selected from a statistical design of experiment method. Based on formation damage relevance, the following factors were considered and varied: pore throat diameter of homogenous porous media (ceramic filter tubes), lithology type, and temperature. The levels of each factor were determined from a mud invasion data base considering high and low limits. Other constant factors were rotary speed, type of lost circulation material (LCM), concentration of LCM, and pressure. An LCM was carefully added to the WBM to reduce the fluid's invasion. Dynamic wellbore condition (pipe rotation only) was simulated with a drilling simulator, capable of rotating a shaft that is centered between the inner diameter of the damaged porous media. Using this approach, the formation damage profile of the WBM on four different lithologies was investigated. The results revealed that rock permeability and porosity are critical factors that control mud invasion, damage propensity, and filter cake permeability profile. Statistical analysis showed that increase in temperature can significantly increase the degree of mud solids cross flow and fines mobilization through the porous media. Thus, leading to the reduction of formation permeability. In a radial system, ceramic filter tubes representing homogenous porous media are often used to quantify mud invasion. However, further investigation revealed no significant change in the damage profile exhibited by the two (5μm and 20μm) pore throat diameter filter tubes used in this study. These filter tubes are typically calibrated to match permeability values of actual rocks, but are not true representation of lithology complexities. The novelty of this study lies in integrating different constant and varying mud invasion factors in relation to the damage of four lithology types.
Development of Environmentally Friendly Epoxies for Well Conformance
Authors: Bertram F. , Tuxen A. , Nielsen T. B. 
Published: January 2018

Abstract
Non-conformance is a common reason for lower oil production in mature fields, and there is a great need for new conformance chemicals that can help restore well conformance and improve reservoir sweep. This paper discusses the development and testing of a new environmentally friendly epoxy that can improve well conformance. A new epoxy formulation has been developed and it is based entirely on environmentally friendly chemicals. This formulation has characteristics similar to conventional epoxies, such as strength and tunable curing time. The developed epoxy offers an environmentally friendly alternative to conventional epoxies and resins, which rely on chemicals that are toxic to the aquatic environment. This epoxy may also be used for well abandonment or hydraulic fracturing.
Modern Fracturing Revitalizes Dormant Technologies: A Case History
Authors: Li Chunlou , Carman Paul S , Davis Brian J 
Published: January 2018

Abstract
Innovation continues to be a driving force within the petroleum industry, particularly in the service sector. Technological breakthroughs often differentiate winners and losers in this highly competitive environment and frequently lead to improved production and real value. Advances this century in hydraulic fracturing technologies have combined to reshape the global oil market by making tight gas and mudstone unconventional plays more viable. Conversely, technologies developed decades ago have also consistently shown new life and new applications when combined with these recent technological innovations.
The successful application of a revitalized non-aqueous hydraulic fracturing fluid system, first developed in the early 90's for diesel and crude oil to tackle some of the most sensitive and technically challenging formations, is documented in this case history. A brief summary of the historical application of this fracturing fluid system and the reasons for lack of applications is included. The current application of this technology, in tandem with a new refined mineral oil based fluid system energized with CO2, found new life for stimulation of the multifaceted Vicksburg formation in South Texas. Vicksburg formation characterization, treatment designs and post-treatment well production performances are reviewed. A short formation evaluation and engineering analysis are also provided to help understand the formation-related challenges and working mechanisms for this fracturing fluid system.
Offset wells completed with alternate technologies during the same time period were weighed against wells treated with the updated 1990's era technology. The revitalized system surpassed these comparative technologies in terms of both cumulative hydrocarbon production and decreased decline rates.
This case history demonstrates not only the efficacy of the documented fracturing treatment design, but also the value in combining old and new technologies as an effective method to provide innovative solutions in challenging reservoirs.
Downhole Gauge Data Analysis of Open-Hole Gravel Packing Treatments: Methodology and Examples
Authors: Kumar A. , Beldongar M. , Agee D. , Gadiyar B. R. , Parlar M. 
Published: January 2018

Abstract
Downhole gauge (DHG) data analysis is a powerful tool in not only identifying, or minimizing the potential number of, root causes for any failures that may occur during gravel packing, but also in either verifying or calibrating friction pressure data used in gravel placement simulations. Although downhole pressure and temperature gauges are often used in open-hole gravel packing and expertise in analyzing the data certainly exists in companies that routinely use downhole gauges, there is no publication that comprehensively discusses the methodology. DHG data analysis in general requires more information than the gauge data itself. This includes logs, wellbore schematic, pumping schedule, fluid properties, return flow measurements, daily rig reports, and data relevant to displacements.
The objective of this paper is to provide guidelines for DHG data analysis to completion engineers who are not routinely involved and thus not experts in such analysis, by detailing the factors that must be kept in mind, offering a methodology and demonstrate the methodology with several examples.
Fines-Migration-Assisted Waterflooding to Improve Sweep Efficiency Analytical Model
Authors: Borazjani Sara , Behr Aron , Genolet Luis Carlos , Kowollik Patrick , Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: January 2018

Abstract
We derive a general system of equations accounting for two-phase fines migration with fines mobilization by injected water with different salinity, rock plugging by the migrating fines and consequent permeability damage in the swept reservoir zones. The analytical model derived contains explicit formulae for water-saturation and ion-concentration fronts along with pressure drop and water-cut in production wells. The model developed is applied to the cases of heavy oils, in low consolidated rocks with different clay composition and different injected and formation water compositions.
We show that non-equilibrium effects of the delayed fines release highly affect incremental oil during injection of different-salinity water. The oil-recovery is maximum for fast fines release. For slow fines release, the recovery tends to that of "normal" waterflooding.
The fines-migration-assisted smart waterflood is successful in reservoirs with a high content of fines-generating clays in the rocks (kaolinite, illite, and chlorite).
A novel analytical model presented in the paper allows predicting reservoir behavior and incremental oil for different compositions of injected water and clay contents in the rock. It permits recommending ionic-composition for the injected water.
Skin Factor Equations for Anisotropic Wormhole Networks and Limited Entry Completions
Authors: Schwalbert Mateus Palharini , Zhu Ding , Hill A. Daniel 
Published: January 2018

Abstract
It was recently shown that anisotropic wormhole networks may arise from the acidizing of anisotropic carbonates. In openhole or cased and densely perforated completions, where in isotropic formations the wormhole network would be expected to be radial around the well, the actual stimulated region may be elliptical in anisotropic formations. Analogously, in completions where the limited entry technique is used, the wormhole network is expected to be spherical in isotropic formations, but it may actually be ellipsoidal in anisotropic formations. That has an impact on the well performance and should be taken into account when designing the acidizing treatment and the completion. At the same time, the use of a limited entry technique may result in better stimulation coverage and also longer wormholes, but it may also result in a partial completion skin factor, impairing the productivity from the stimulated well. This should be taken into account when estimating the stimulated well productivity.
In this study two main topics are analyzed: the impact of wormhole network anisotropy and the impact of a limited entry completion. Both radial and spherical wormhole propagation patterns are considered, to be applied in both openhole and limited entry completions. The differences in well performance is studied for each case, and analytical equations for the skin factor resulting from each scenario are presented.
The anisotropic wormhole networks are obtained from numerical simulations using the averaged continuum model, and the results are validated with experimental data. The analysis of the well performance is made through simulation of the flow in the reservoir with the different stimulated regions.
The results show that for highly anisotropic formations the wormhole network anisotropy may have a great impact on the acidized well performance and this should be taken into account in the acidizing treatment design. It was observed that the anisotropic wormhole networks present lower productivity than equally sized isotropic stimulated regions. Hence, equations like Hawkins formula should not be used for estimating the skin factor from anisotropic wormhole networks, and the equations proposed in this work should be used instead.
Specifically, the impact of anisotropic wormhole networks is large when the limited entry technique is used. It is shown that for this type of completion there is an optimum stimulation coverage of about 60 to 70%, and the perforation density required to obtain for a given acid volume depends strongly on the wormholes' anisotropy. The skin factor equations proposed in this work for the stimulation with limited entry completion should be used for obtaining the optimum perforation density for a given scenario.
Understanding the Impact of Production Slugging Behavior on Near-Wellbore Hydraulic Fracture and Formation Integrity
Authors: Lu Haidan , Anifowosh Olatunbosun , Xu Lili 
Published: January 2018

Abstract
Numerous studies on unconventional shale well production data have shown that downhole pressure fluctuations can exceed 300 psig during a slugging period. Such pressure fluctuation will result in very high drawdown and could lead to near-wellbore formation damage when the rock failure criterion was met. An engineering workflow was developed to investigate the impact of multiphase slugging events on cemented casing plug and perforation (CCPP)and open hole sliding sleeves (OHSS) completions. Based on transient pressure analysis and geomechanical evaluation, safety operational envelope was generated to minimize the risk of formation damage due to slugging behavior.
In this study, a dynamic multiphase flow simulator was used to predict the pressure amplitude and frequency during the slugging events in both a CCPP and OHSS completion configuration. The results from the simulation were then incorporated into a geomechanical model to analyze and identify potential hydraulic fracture closure and formation damage concerns, which can compromise well performance.
The results from this study show that OHSS completion is more vulnerable to damage during the downhole slugging period than a CCPP completion. However, severe formation and fracture damage could occur during downhole slugging for CCPP well if the well is operated outside the safety operational envelope. Results from the two case studies led to the conclusion that it is crucial to consider the effect of downhole slugging on near-wellbore fracture and formation integrity to avoid permanent and irreversible damage.
Application of Solid Scale Inhibitor in Annular Space to Reduce Well Intervention Cost
Authors: Bhaduri Sumit , Shen Dong , Gupta D. V. 
Published: January 2018

Abstract
Formation damage caused by mineral scale development is one of the major reasons resulting in reduction of hydrocarbon production during a well's life cycle. Scale inhibitors are most widely used to control scale deposition in producing wells either by adding them directly to fracturing fluids in wells where stimulation treatment is planned or by performing remedial squeeze treatments. Prolonged protection can be achieved by adding proppant-sized solid inhibitor during the stimulation treatment. The current study addresses the benefits of alternate methods of placing solid inhibitor depending on the well completion system. In the case where stimulation treatment is not planned, the solid inhibitor can be placed in the annular space between the production tubing and formation in the long open-hole horizontal well to provide extended protection as the well starts to produce. This solid inhibitor once depleted as evidenced by residual analysis can be recharged effectively by injecting liquid inhibitors that restores the effectiveness, allowing extension of protection life-times.
An appropriate inhibitor chemical was first identified for the treatment from the produced water scaling analysis. A suitable solid scale inhibitor was prepared by adsorbing this chemical onto a high surface area water/oil insoluble substrate, and multiple surface modifications made to control the inhibitor release rate. The long term inhibitor chemical release profile was evaluated by packing this solid inhibitor into a column and eluting with synthetic produced water at expected bottom-hole temperatures of 200°F.
The solid inhibitor elution tests show long protection times when solid inhibitor was applied. The projected inhibitor protection would be more than 60,000 pore volumes (PVs) of produced water before the inhibitor chemical was substantially depleted. In a well, 3000 pounds of this inhibitor can be potentially placed in the annular space, which would result in preventing scaling for 330 thousand barrels of water being produced, with protection life-time of more than 5 years (at 170 barrels of water per day). The presence of high surface area substrate allows inhibitor to be recharged after inhibitor depletion. The efficiency of the inhibitor recharge application was investigated by a series of column experiments.
Placing the solid inhibitor into the annular space will delay the requirement for scale squeeze treatments significantly, and reduce the overall well maintenance cost for the operator, particularly in an offshore environment. The ability of the solid inhibitor to be re-charged using conventional scale squeeze chemistry enables more chemicals to be retained when subsequent squeeze is potentially performed on the wells.
Successful Installation of Horizontal Openhole Gravel-Pack Completions in Low Fracture Gradient Environment: A Case History from Deepwater West Africa
Authors: Jeanpert J. , Banning T. , Abad C. , Mbamalu I. , Hardy J. 
Published: January 2018

Abstract
This paper presents the design and execution of an openhole gravel-pack completion campaign in deepwater West Africa. Based on field history and past challenges, a novel approach was implemented to address the low fracture gradient.
Various aspects of the gravel pack design are discussed - drilling and gravel pack fluid selection, screen selection, openhole displacement, filtercake removal, placement technique, and pumping design. The placement method uses screens with shunt tubes, an existing technology, that was deployed in an unconventional manner. Post treatment evaluation and analysis are also presented. Results are compared to conventional gravel pack placement and to previous wells from this field.
The success of the first completion enabled an increase in openhole length in subsequent wells. The understanding of the packing sequence was consolidated after each well, driving the optimization of the pumping schedule.
Fracture Permeability of Activated Calcite Veins to Water and Gas
Authors: Mokhtari Mehdi , Tutuncu Azra N. 
Published: January 2018

Abstract
Many shale and limestone formations exhibit natural fractures in the form of calcite veins. Although these natural fractures might be sealed, they are prone to activation in hydraulic fracturing operation due to their low mechanical properties. Once these fracture are activated, the flow in such fractures without proppants play a role not only in production performance but also in analyzing the mechanisms responsible for the low recovery of water flowback. To address this issue, we created induced fractures within calcite veins of Niobrara formation using indirect tensile experiment and fracture permeability experiments were conducted by injecting both water and gas. The results of fracture permeability tests in Niobrara formation were compared with the results of fracture permeability tests in granite sample. The effective fracture permeability to water is significantly lower than the fracture permeability to gas in calcite veins while the fracture permeability of granite sample to both water and gas is almost similar. Comparing the fracture permeability of the Niobrara sample with the granite sample provides some insights into the possibility of water trapping microfractures as a possible reason for low water-flowback recovery. Besides the interaction of water with rock, fracture roughness can be another mechanism affecting fracture permeability. To this end, the topographic surface of samples were measured by laser profilometer and the fluid flow in rough fractures were simulated numerically to analyze the effect of roughness on fracture permeability.