bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of Asset-Wide Chemical Treatment Programs
Authors: Awny Z , Babaniyazov A
Published: January 2016

An effective chemical treatment program should reduce the rate of well failures while enhancing well productivity and minimizing cost. The unique challenges to achieving these goals include the variation in the downhole conditions, fluid composition, completion types and number of wells. The execution of chemical programs often relies on third party vendors with a vast resource base and proven technology. These traits, however, must be coupled with knowledge of the well history and proper oversight from operations, facilities, and production engineering groups. Managing and effectively utilizing collected data helps to move from "blanket type" chemical programs to a more targeted well-by-well approach.

This work uncovers several opportunities for improvement in already established chemical programs. It is especially beneficial for the onshore fields which are challenged with hundreds or even thousands of wells. The systematic improvement strategy applied in this study began by assessing existing data for identification of scaling, corrosion, and organic deposition problems. This allowed the Local Chemical Management Team (LCMT) to reveal gaps in the information needed for a more comprehensive understanding of formation damage and flow assurance issues. Proper identification of controlling damage type per formation and area of the field enabled redesigning of well completions, testing of water compatibilities for fracture stimulation, and customization of acid treatments with improved acid placement and production uplift.

Early attempts to collect fluid samples and integrate water, gas and solid analysis in the scale prediction modeling software revealed the critical nature of quality checks in sampling procedures, field tests, and lab reports. The lab audits and chemical program data management led to reorganization of the database structure and improvement in measuring and reporting of the results to the LCMT. The value of information gained by laboratory tests offered by the chemical provider was assessed in current field settings and communicated to engineering and operations personnel. A better understanding of organic deposits also supplemented wellbore and sand face clean outs.

Inclusion of a flow assurance focus in an established corrosion and well failure prevention program increased well productivity and decreased operating cost per well. Improvements in the database structure included utilization of historical data for treatment optimization, integration of oil, water, and gas with quantitative solids analysis, and the establishment of key performance metrics and reporting procedures. Customization of remedial treatments per zone and geographic location, in addition to a review of well histories and completions complemented production optimization practices. Awareness of flow assurance issues and chemical management programs was provided to operations and engineering staff through a number of on-site training sessions.
The Effect of Evolved CO2 on Wormhole Propagation in Carbonate Acidizing
Authors: Cheng H. , Zhu D. , Hill A. D.
Published: January 2016

Matrix acidizing is a commonly used stimulation technique for oil and gas wells. In carbonate reservoirs, acid is injected into the formation to dissolve carbonate rock in order to create highly permeable channels called wormholes. For a constant volume of acid injection, different injection rates create wormholes with different lengths. The injection rate that creates the deepest wormhole is called the optimal acid injection rate. Optimal injection rate is determined in laboratory experiments by measuring the pore volumes to breakthrough – the volume of acid injected in a core flood for the wormhole to reach the exit end of the core, normalized by the initial pore volume of the core. HCl is commonly used for carbonate acidizing treatments. The reaction between HCl and CaCO3 createsCO2. At laboratory conditions, 1000 psi back pressure is commonly used for acidizing experiment to keep CO2 in solution. However, based on the solubility of CO2 in water, 1000 psi may not be enough to keep CO2 in solution. In such a case, undissolved CO2 can be present as a gaseous phase in the system. As the properties of CO2 change with pressure and temperature, in order to accurately evaluate optimal acid injection conditions, the evolution of CO2 and its effect on wormhole propagation efficiency need to be investigated.

In this study, we conducted core flooding experiments to examine the effects of evolved CO2 onwormholing behavior. The experiments were conducted at both room temperature and at an elevated temperature. Different back pressures from 500 psi to 3000 psi were applied in the experiments. The Buijse-Glasbergen model was usedfor curve fitting to obtain the optimal acid flux and optimal pore volume to break through for each experiment. Computerized Tomography (CT) scan images were taken for each core sample after acid injection to evaluate the structures of the wormholes.

The test results show that the effect of CO2 on wormholing depends on the temperature, pressure, and injection rate. For low injection rate, CO2 present as a gaseous phase slows down wormhole propagation efficiency dramatically and enlarged wormhole diameter is observed. At injection rates above the optimal rate, the effect of CO2 is less pronounced, particularly at higher temperatures.
Experimental and Numerical Investigation of a Novel Technique for Perforation in Petroleum Reservoir
Authors: Zheng L. , Rahman M. A. , Ahammad M. J. , Butt S. D. , Alam J. M.
Published: January 2016

Formation damage in petroleum reservoirs is a combination of many complicated phenomena. The formation damage reduces the productivity index significantly. The damage mechanisms may occur from the stage of drilling process to tertiary oil recovery stage. This study investigates the formation damage of petroleum wells due to shooting in well completion. The study is conducted with numerical and experimental investigations. The experimental set is a prototype. Two techniques are considered for numerical simulations: one is ANSYS-CFX and other one is a computational methodology which is based on weighted residual collocation method. Single phase and two-phase flows in porous media have been taken into consideration to explore the productivity index, which is affected by formation damage. Therefore, a better understanding of damage mechanisms for various reservoir conditions can lead to optimize oil recovery rate.
Stochastic Analysis of Inorganic Scale Buildup in Seawater Injection of Waterflooding Operations
Authors: Temizel Cenk , Tiwari Aditya , Tuna Tayfun
Published: January 2016

Started in the late 1800s in the US, water being relatively inexpensive and readily available in large volumes and as being very effective at significantly increasing oil recovery, waterflooding has been the most common secondary recovery method applied throughout the world, contributing to pressure maintenance in the reservoir and displacing the oil phase. While there are several parameters that influence the performance of a waterflood, water quality is one of the important factors as it may cause scaling in the injection wells as well as some formation damage through chemical phenomena such as cation exchange in the reservoir resulting in decreased the recoveries.

As waterfloods continue over decades, prevention of scale formation becomes a more significant factor that needs to be properly treated. The precipitation of inorganic scale is a major issue in injecting brines with a high concentration of divalent ions. The scaling tendency of water is highly correlated with the hardness of the injection water.

Following corrosion, insoluble iron precipitates can cause damage in injection wells where precipitates can lead to severe reductions in well injectivity. Water needs to be treated in a proper way if the water contains high concentrations of calcium, magnesium or iron. In most waterflood applications, seawater needs to be used and this phenomenon is also an issue when injecting seawater into formations that contains brines with high salinity.

In this study, a comprehensive analysis of this common problem is provided by investigating the significance of parameters affecting the severity of the scale through utilizing a seawater scale buildup model to be simulated using a commercial simulator along with an in-depth review of previous studies.
Solubility and Inhibition Efficiency of Phosphonate Scale Inhibitor_Calcium_Magnesium Complexes for Application in Precipitation Squeeze Treatment
Authors: Valiakhmetova A. , Sorbie K. S. , Boak L. S. , Shaw S. S.
Published: January 2016

Scale inhibitor (SI) squeeze treatments are applied extensively for controlling scale formation during oil production. The current research involves phosphonate/metal precipitate studies in the context of precipitation squeeze treatments. The main focus here is on the precipitation and solubility behaviour of the SI_Ca_Mg complexes of HEDP (di-phosphonate), DETPMP (penta-phosphonate) and OMTHP (hexa-phosphonate) phosphonate Sis; these phosphonate/mixed Ca/Mg divalent precipitates are denoted as SI_Can1_Mgn2, where n1 and n2 are the stoichiometric ratios of Ca and Mg to SI.

Precipitation experiments with SI_Can1_Mgn2 species were carried out over the temperature range, 20–95°C, while varying the Mg/Ca molar ratio over a wide range from all Ca to all Mg. These precipitates were formed in MgCl2·6H2O/CaCl2·6H2O brine solutions with appropriate molar ratios of metals, then separated from supernatant by filtration. Subsequently, the solubility of the collected precipitate was found in a solution of the same Mg/Ca molar composition from which it was prepared. In this type of experiment, the solubility of the SI_Can1_Mgn2 precipitate without any re-speciation is determined. In addition, another type of solubility experiment was carried out for a precipitate formed in a brine with one fixed Mg/Ca ratio and this was subsequently placed into a solution with different Mg/Ca compositions (from all Ca to all Mg). In these experiments, re-speciation of the precipitate may occur.

We have been able to establish the solubility (Cs) of the precipitates of 3 SIs (HEDP, OMTHP and DETPMP) as a function of both temperature and Mg/Ca molar ratio. It has been shown, that the solubility (Cs) of precipitate is in equilibrium with Mg and Ca concentrations in solution and any change of these parameters leads to solubility (Cs) variation. All phosphonate/metal precipitates become less soluble with increasing temperature and much more soluble as the proportion of Mg increases. We have found, that any change in Mg/Ca ratio of brine does lead to a re-distribution of Ca, Mg and SI concentrations in a given precipitate and bulk solution, and hence leads to some variation in the precipitate solubility.

In addition, the inhibition efficiency (IE) of precipitated and then re-dissolved HEDP, OMTHP and DETPMP SIs was tested and was compared with the IE of industrial stock products. We show that, unlike polymeric SI precipitates, the inhibition activity of phosphonate SIs does not depend very significantly on the precipitation process and the IE of precipitated and re-dissolved SI_Ca and SI_Ca_Mg complex is very close to that of the industrial stock solutions. These results can be used directly for modelling phosphonates precipitation squeeze treatments and the significance of these results for field applications is explained.
Perforating System Performance at Downhole Conditions: Recent Advances in Modeling and Prediction
Authors: Grove B. , Harvey J. , Martin A.
Published: January 2016

Modeling of perforating system performance at downhole conditions has received significant attention in recent years. This is due to increased recognition of the importance that perforating plays in well performance, and ultimately asset value.

To this end, models have been recently developed to more reliably predict key downhole parameters, including formation penetration depth, perforation cleanup, and skin. These new models have been incorporated into a software tool, which enables users to optimize perforating designs around completion and production objectives, while considering operational constraints.

This paper summarizes these recent advances, some previously unpublished, and briefly summarizes recent case studies highlighting the impact of the improved modeling capabilities.
The Impact of Corrosion Inhibitors on Relative Permeability of Water Injector and Production Well Performance
Authors: Johnston C. J. , Sutherland L. , Jordan M. M.
Published: January 2016

In many oilfields with carbonate and sandstone reservoirs corrosion inhibitors are applied to control corrosion within production wells via continuous or batch treatments of the tubing and in water injection wells (seawater/aquifer and produced water) via continuous injection. The corrosion inhibitors within these formulations are fundamentally designed to control corrosion at the lowest treatment rate possible with little thought given to their potential impact on the wettability of the reservoir rock if they were to contact it.

This paper will present details from a set of corefloods which look at seawater and produced water re injection (PWRI) under matrix flow conditions within carbonate and sandstone cores.

The observed stimulation in the water injection tests suggests that it is possible for the injector wells to take more water due to the interaction of the corrosion inhibitors tested for both matrix types. The corrosion inhibitor solution when applied to cores which had been solvent cleaned showed stimulation (increased brine permeability) suggesting that the chemical interacted with mineral surfaces rather than improved brine permeability due to change in residual oil saturation within the pore space of the rock.

Results for corrosion inhibitor application to production wells where the chemical is allowed to flow out of the production tubing during "batch" tubing treatments are also presented. The production well data is in marked contrast to the water injector results, the change in wettability in both carbonate and sandstone observed with the introduction of the corrosion inhibitors tested would reduce oil production and increase water production due to the change in relative permeability observed with corrosion inhibitor adsorption onto the mineral substrate (both silicates and carbonate).

The paper outlines the mechanism of stimulation for water injection wells and highlights the damage potential of a flow assurance challenge that is receiving a significant amount of focus within both onshore and offshore fields at this time.
Results from Response Surface Methodology in the Study of Novel Temporary and Permanent Clay Stabilizers
Authors: Aften Carl W. , Zhang Yanqi Joy
Published: January 2016

The performance results from a systematic study of novel and contemporary clay stabilizers are provided. These interactions range from synergistic to antagonistic and are presented on a response surface with good correlation. Both organic and inorganic permanent and temporary clay stabilizers were studied. Some of these novel effective inhibitors have HIMS ratings lower than choline chloride.

Various clay stabilizers are employed when stimulation techniques requiring aqueous based fluids are necessary in water sensitive formations. Typically, if swelling or migrating clays are present, temporary or permanent stabilizers are utilized. Low molecular weight temporary stabilizers, as a rule, perform only above a critical level concentration, but as the stabilizer's concentration diminishes in the fracturing fluid due to flowback, formation fluid displacement, or other mechanisms, the clay can swell, reducing porosity and permeability. Permanent stabilizers are generally higher molecular weight and can adhere to single or multiple clay platelets, thus dissolution of the stabilizer into the fluid is not favored, and the beneficial anti-swelling effect is of higher duration.

This study was set up using Central Composite Design of Experiments. Performance testing was conducted using a low pressure Bariod fluid loss cell. A set concentration of unbenefited sodium bentonite was blended into water at a specific RPM and duration in the presence of the particular stabilizers, then placed in the cell, sealed, and pressure was applied. Finally leak off rates were measured. The slope of the leak off curve was calculated and plotted versus dosage. The slopes and response surfaces observed had excellent correlation. Additive effects and synergies were noted.

The design of efficient temporary clay stabilizers can be directly linked to performance. Novel temporary clay stabilizers competitive with choline chloride in both performance and environmental profile should be welcomed in stimulation. The duration of the stabilization could also be studied using this test method since porous media experimentation is difficult to perform.
Obtaining Comparable and Relevant Formation Swelling Sensitivity Data from CST: Is this Even Possible?
Authors: Benoit Denise , Montenegro-Galindo G. Rocio , Anderson Katelyn L. , Hoeman Kurt W.
Published: January 2016

Capillary suction time (CST) tests with drilling and treatment fluids have been used to characterize formations for swelling tendencies since 1983. However, in most cases, it is not possible to establish comparisons between data sets acquired in different laboratories or at different times. This paper evaluates how certain factors impact CST and offers useable constraints to the method to establish relevant comparisons across different samples.

The basic operation of CST tests is simple: slurries of formation materials are prepared in treatment fluids, and the time required for free liquid to travel a calibrated distance in standard porous paper is measured. Swelling formation materials consume free water from the slurry, decreasing the available free water and reducing the permeability of the filter cake, which increases the CST (Underdown and Conway 1992). Several factors can artificially alter the measured time, such as materials blocking the flow of fluid. Extensive experimentation to determine the most prevalent factors and minimize their significance led to a robust, sample-to-sample comparison methodology.

The work presented in this paper considers changes in CST response based on the source of formation materials (outcrop samples, drilled cores, and cleaned drill cuttings), the composition [standard spiked samples and natural formation materials analytically characterized by X-ray diffraction (XRD) and cationic exchange capacity (CEC)], and sample preparation (grinding method, particle size, shear rate, shear time, slurry volume, and fluid effects) to determine how each factor impacts the measured CST. Ultimately, a method for obtaining consistent sample preparations and data interpretation for CST is presented. This technique is especially useful in low-permeability formations where other conventional methods, such as core flood tests, cannot be used. In particular, this technique has proven to be very useful when no core formation materials are available and only drilling cuttings can be obtained. To test the robustness of the methodology, shale formation materials from 30 unique wells with clay contents from 6 to 64% were characterized. Measured CST values for each material were used to assess the damage potential in relevant fluids and determine treatment recommendations. By implementing the proper testing constraints, the CST can be used as a reliable, quick, low-cost, easy-to-run, and quantifiable analytical technique for sample-to-sample comparisons.

By controlling the parameters involved with sample preparation, CST can be used as a reliable means to accurately determine the formation material's sensitivity to a given fluid on a well-by-well basis.
Pressure-Dependent Induced Fracture Complexity or Natural Fracture Contribution Evaluation in Unconventional Reservoirs: How to Assure Their Long-Term Benefit
Authors: Sierra Leopoldo
Published: January 2016

Induced fracture complexity or natural fracture contribution to the productivity or hydrocarbon recovery optimization of unconventional reservoirs is fully accepted in the industry but not properly quantified, especially for complex environments where the high induced stresses can affect their shortor long-term conductivity and benefit. With respect to an unconventional reservoir’s matrix permeability, induced fracture complexity or existing natural fracture conductivity can also be pressure-dependent, which will drastically affect well productivity if an operator does not properly consider permeability, complexity, and conductivity during the well-completion stage.

If the pressure-dependent induced fracture complexity is packed as much as possible with small proppant or a microproppant system during the well-completion stage to assure its conductivity, the induced complexity will have a positive impact on well productivity; otherwise, only the stimulation fluid efficiency will be affected. Conversely, for existing pressure-dependent natural fractures, proper or limited packing is required to help minimize the negative impact of overpacking the open natural fractures and altering their original conductivity.

Considering the different completion scenarios and inclusion of small proppants or a microproppant system in the stimulation process, this paper quantifies the inherent benefits of the pressure-dependent induced fracture complexity and pressure-dependent natural fractures by performing numerous reservoir simulations of unconventional gas reservoirs.
Damage Remediation in a Mature Field Reservoir by Applying a Customized Treatment Using Surface Active Additives and Diversion Technologies: Case Histories from San Francisco Field
Authors: Lucuara German , Usuriaga Jose , Campo Pablo , Sepulveda Edwin , Pacheco Carlos
Published: January 2016

This paper discusses successful damage remediation performed in more than 10 wells in a mature oil field producing under a developed waterflooding project in Colombia. The primary damage mechanism observed is associated with a detriment to production related to reduced relative permeability caused by wettability preferences.

A chemical treatment was proposed that consisted of crude oil with efficient and effective surface active additives, such as microemulsions (MEs) and/or formation mobility modifiers (FMMs) and associative polymers (APs) for a proper diversion. The treatment was proposed as an effective method to restore near-wellbore (NWB) permeability in or through the damaged zone in the formation, resulting in production recovery. All matrix-stimulation treatments were conducted rigless by means of an annulus without affecting the artificial lift method and resulted in a significant time and cost savings.

Laboratory data confirmed the ability of the MEs and FMMs to modify interfacial tensions (IFTs) and contact angles. These materials helped promote a change in the degree of wetting of the system, which is dependent on the adhesion tension (the product of the IFT by the cosine of the contact angle). During well treatments, surface pressure spikes during the diversion stages were associated with the arrival of the APs at the perforations and were clearly observed during the development of the treatments, revealing that effective diversion was achieved. Finally, post-stimulation treatment data have shown positive results, confirming the effectiveness of combining these technologies.

This paper discusses how the synergy of using surface active additives with diversion technologies can yield productivity increase in mature oil reservoirs and improve the level of sustainability of current field production.
Ability of a Filter Cake Breaker to Diffuse into Completion Brine and Packed Gravel
Authors: Allogo Clotaire-Marie Eyaa , Ravitz Raymond , Gadiyar Bala , King'Ori Solomon
Published: January 2016

Successful completion of an open hole gravel pack well requires a deposition of a low-permeable filter cake on the wellbore to seal and protect the permeable reservoir formation during drilling and completion operations. The deposited filter cake is removed with the aid of a breaker system before the well is put on production. The placement of a breaker post gravel packing operation brings up a concern regarding the efficiency of the breaker system due to possibly limited contact with filter cake.

This study was initiated to simulate the ability of a filter cake breaker system to diffuse through gravel pack carrier fluids inside a screen base pipe and gravel pack. A new apparatus simulating the diffusion and testing protocol were created and used to perform this study. During the experiments breaker system migrated/diffused through a simulated base pipe and packed proppant filled with 10.3 ppg CaCl2 in less than 24 hours. This proves the ability of a breaker system to contact filter cake in post spot situations.

This paper describes a new method built to perform simulations with the objective to calculate the diffusion time and to document the ability of the filter cake breaker to migrate and/or diffuse through a gravel pack at ambient conditions. The paper also establishes the best practices in the design of an effective filter cake breaker system and pumping operations based on the breaker diffusion/migration mechanism.
A Novel Application of Standard Surveillance Techniques to Formation Damage Control by Identifying the Location of the Obstruction and Quantifying Skin Type
Authors: Gonzalez Fabio , Gonzalez Doris , Pietrobon Marney , Yilmaz Timur , Pecoraro Jered , Stewart Carlos , Giles Duvivier
Published: January 2016

Asphaltene is a naturally occurring constituent of crude oil consisting of high molecular weight components which in most cases are in equilibrium within the liquid phase at initial reservoir conditions. As crude oil is produced and the energy of the reservoir depletes, the equilibrium is distressed and asphaltene can precipitate out of the liquid phase. Precipitation of asphaltenes is a condition for asphaltenes deposition, but precipitation will not always result in deposition. Deposition of asphaltene has the potential to negatively impact productivity of oil wells up to the point of completely shutting in production if the problem is not identified on time and mitigated and/or treated properly. The objective of this work is to present a systematic process for data acquisition and data analysis to identify the region in the well production system where asphaltene deposition is occurring leading to a properly designed operating strategy for production and interventions.

In order to identify and mitigate (or treat) the organic damage caused by asphaltene deposition near the wellbore, a methodical surveillance plan has been developed to acquire and interpret the required information at the right stage of the oil field development. The methodology consists of combining two different approaches: 1) Laboratory analysis of reservoir fluid samples using near infrared (NIR), high pressure microscope (HPM), and particle size analysis (PSA); and 2) Pressure transient analysis and multi-rate testing.

This procedure has allowed us to determine when skin develops and where in the well production system between the perforations and the downhole gauge asphaltene deposition is occurring. Specifically, we have been able to integrate results of asphaltene onset pressure (AOP) with quantification of total damage and the evolution of Darcy versus non-Darcy skin to identify if damage is worsening in the formation rock or anywhere below the permanently installed downhole pressure gauge. This paper presents an innovative approach as the integration of reservoir fluid characterization; pressure transient analysis and multi-rate testing have been combined to fully assess the damage mechanism, location of the damage, and the evolution of damage as a function of cumulative production. As a result of this methodology we have been able to properly design and schedule treatments to enhance well productivity and extend the longevity of the wells without exorbitant operating expenses and unnecessary downtime. Individually, these interventions have generated economic value and greatly increased the worth of deepwater oil fields in the Gulf of Mexico through sustainable delivery.
Near Wellbore Damage and Types of Skin Depending on Mechanism of Damage
Authors: Patel Mahesh Chandra , Singh Aaditya
Published: January 2016

Near wellbore damage has been a topic of great attention over last many decades. Typical measures of formation damage is skin factor (S) which is a hydrodynamic parameter characterizing additional resistance to flow of fluids in the near borehole zone of the reservoir, leading to reduced production (yield) compared to the perfect (ideal) wells. This has been a great attention of topic because it directly effects on formation fluid productivity from the concerning well. Reasons behind formation of this damage can be combinations of several mechanisms are clay particle swelling, fluid loss or change in formation water saturation, wettability reversal, Emulsion blockage, Mutual precipitation of soluble salts in wellbore-fluid filtrate and formation water, Deposition of paraffins or asphaltenes, Fines migration etc. Operations which are usually leads to those mechanisms to happen are drilling, cementing, well completion, work-over operations, production of fluids, injection of fluids and Operations to isolate water production etc.

This paper describes mechanisms of the formation damage. And introduces types of skins depending on the mechanism of damage and source operation, and Types of skin are The mechanical or formation damage skin factors (Sd)Completion pseudo skin factor (Sp)Partial penetration skin factor (Spp)-Geometrical pseudo skin factor (Sg)Multiphase pseudo skin factor (Sm)Non-Darcy flow or Rate-dependent high velocity or turbulent flow pseudoskin factor (Sturb)

This paper also describes all type of skin in detail with mathematical models given to calculate the skin individually as well as effective skin.
Guar Replacement with Synthetic Polymers - Utica Shale Case Histories
Authors: Blamble E. A. , Pyncheon J.
Published: January 2016

This study was conducted to determine the advantages of replacing guar-based polymers with polyacrylamide (PAM) engineered polymers in unconventional shale gas plays. Hydraulic fracturing of unconventional shale gas reservoirs usually consists of low-viscosity slickwater treatments where the water/sand mixture is pumped into the reservoir at high treatment rates (80+ bpm). At such high fluid velocities, the proppant/water slurry is abrasive to fracturing equipment resulting in decreased service life plus higher repair and maintenance costs. Additionally the low-viscosity slurry will allow proppant to fall out of suspension. This causes poor proppant placement in the fracture, leading to decreased well production response. In these situations it is advantageous to use a hybrid design where guar polymers are added to the slurry to increase viscosity and aid in maintaining suspension of the sand. The disadvantage of using guar-based polymers for this application is a polymer residue is left in place following the fracturing treatment, which can decrease the production of the well.

A guar-alternative, PAM, has been developed for use as a friction reducer in slickwater treatments and to increase the viscosity of the water/sand mixture when added in increased concentrations. This PAM has been specifically engineered so that the polymer chain can be broken into discrete units using traditional oxidative breakers and then flowed back out of the well when production begins. This breaking mechanism leaves behind less polymer residue than old-style guar treatments. This system has been used numerous times in the Utica shale and has resulted in superior production performance versus the wells that have been completed in the same area using guar polymers.

This paper will focus on multiple Utica shale wells that have been successfully completed using the PAM engineered polymer scheme. Production data on a statistically significant number of offset wells will be presented, drawing from publically available production data. Production periods of up to 2 years will be included to illustrate the advantages this system has over the traditional hybrid fracturing using guar-based fluid systems. Data will be provided which demonstrates that wells completed using this PAM system produce, on average, 66% more hydrocarbons than offset wells completed using conventional systems.

This paper will demonstrate that there is an effective alternative to guar gel available for use in hydraulic fracturing operations. This alternative solution leaves behind significantly less polymer damage, enhances fracture conductivity, and improves hydrocarbon production.
An Improved Wormhole Propagation Model with a Field Example
Authors: Tan Xuehao , Weng Xiaowei , Cohen Charles-Edouard
Published: January 2016

An improved 1D-averaged model for wormhole propagation was developed that considers acid spending and leakoff along wormholes. The 1D-averaged type of model is one of several types that have been developed for predicting wormhole propagation during matrix acidizing treatment in carbonates; other models include discrete models, Darcy-scale 2D and 3D continuum models, and multi-pore-scale network models. Among these models, the 1D-averaged model is commonly applied in acidizing simulation software because of its simplicity.

Most of 1D-averaged models are based on the pore volume to breakthrough correlations developed from core flooding experiments on different rock samples and acid systems. It is also generally assumed that the effect of acid spending is already included in the experimental results. Although this is a reasonable assumption when the wormhole length is shorter than the core length (typically 6 in.), once wormhole penetration is longer than 6 in., the acid spending becomes more significant while acid travels along wormholes due to the reaction between acid and the side walls of wormholes. Meanwhile, acid leak-off through wormhole walls becomes an important factor for longer wormholes. Not considering acid spending and leakoff in relatively longer wormholes may result in overestimation of wormhole penetration depth.

In our model, we adopted an empirical correlation to determine the leak-off velocity profile along wormholes. Then, we developed a numerical model to simulate the non-uniform acid concentration along wormholes. Both the empirical correlation for leak-off velocity profile and the numerical model for acid concentration are validated by comparing to published materials and an independent computational fluid dynamics (CFD) software. As expected, wormhole penetration predicted by the new model shows shorter wormholes than the traditional 1D-averaged model.

We applied the new model to a field case and showed its capability of reasonably matching the downhole pressure during acidizing treatments and PLT data before and after acidizing treatments, which demonstrates the applicability of the model to job design and interpretation in the field.
Analysis of Sand Screen Integrity in Depleting Sandstone Reservoir
Authors: Tallin Andrew , Han Yanhui , Wong George
Published: January 2016

In this paper, sand screen integrity in two depleting reservoirs is evaluated using fluid-mechanical coupling analysis. Both analyses use a numerical model for rock-structure interaction. In the first, a horizontal completion in a soft sandstone reservoir is evaluated. This analysis used laboratory tests to measure the properties of ceramic proppant, the formation sandstone and sand screen. The numerical model included friction hardening and volumetric hardening of the formation, friction hardening of the gravel pack, and the crushing strength of the screen base pipe which were all measured in the laboratory. In the second, a vertical gravel pack in a stiff strong formation was analyzed to evaluate gravel screen contact loads under very high levels of depletion and drawdown. While this analysis did not include a laboratory program, using instead existing core data, it did model the effect of near wellbore damage on the contact load.

The results show that loads on sand control completions can be estimated and the workflow demonstrated here is a way to select durable sand control completions.
Solubility of Barium Sulfate in Formate Brines - New Insight into Solubility Levels and Reaction Mechanisms
Authors: Howard Siv , Anderson Zhao , Parker Stuart
Published: January 2016

It has been known since the 1930's that concentrated brines release barium into solution from barite. The amount of barium released into solution is a function of the molar salt concentration, brine type, temperature, and pressure. Brines containing very high molar concentrations of solute are the most effective at solubilizing barite in well operations. Given the HSE hazard posed by fluids containing soluble barium it is important to know exactly what levels of this heavy metal may be present in high molarity oilfield brine systems that have been contaminated with barite.

An extensive test program has now been conducted to provide new and reliable information on the soluble barium content of potassium- and cesium formate brines that have been exposed to analytical grade barium sulfate at elevated temperatures and then cooled. The effects of formate concentration and the ratio of cesium to potassium in the formate brines were investigated. The brines were tested with and without the addition of carbonate/bicarbonate pH buffer, as a function of exposure temperature and exposure time.

The results of this research confirm results of previous research reported by Shell, indicating that up to 3,500 mg/L of barium can be released from barium sulfate at 100°C (212°F) in the most concentrated potassium formate brines. However, the good news is that soluble barium levels are low in all formate brines that contain carbonate/bicarbonate pH buffer. This is because any dissolved barium will precipitate out as barium carbonate, which is barely soluble in concentrated formate brines.

This new insight into the mechanisms of barite dissolution in buffered and unbuffered formate brines could open the door for the formulation of more advanced fluids for filter cake removal and scale dissolution applications.
Gravel Pack Sizing Criteria - It's Time to Re-Evaluate
Authors: Fischer Christine , Constien Vernon , Vining Carla
Published: January 2016

Correct sizing of Gravel packs for sand retention in Gravel Pack and Frac Pack completions has been a controversial topic for many years dating back to the 1960's. One of the earliest studies completed, and still most often cited, was by Saucier in 1974. Saucier proposed sizing the gravel based on the median size of the formation (d50 * 6). The Saucier criteria is still often used and works well for many applications. In 1998, Tiffin furthered the Saucier work in SPE 39437 and suggested that for some specific formation sands, the gravel could be size as much as 7–8 times the median size of the formation. In both bodies of work, the median size of the formation is really the only formation size parameter that is considered in the gravel pack size selection.

In the ensuing years, much has been published regarding sand retention testing, but the criteria for gravel pack size selection has not been updated or addressed. In 2012 Martch et al. suggested a new method which correlated sand retention data to a ratio of the effective formation size and the gravel pack pore size (SPE 151865).

In this series of work, the gravel pack pore size is further evaluated using the permeability of the gravel pack and other methods. A new sizing method is proposed which is based on the "effective formation size", (Formation d50 / Uniformity Coefficient) as well as the gravel pack pore size. In this manner, the gravel pack is effectively treated like a screen and the selection of gravel pack size becomes similar to the selection of screen size.

The sand retention testing used to validate this selection criteria was performed using both constant drawdown and constant rate test methods. These represent the two most common methods used in the industry. The amount of solids produced, the size of the solids produced, and the initial and final gravel pack permeability are measured and reported for each test.
Would You Like Good Lab Results or a Productive Well? Getting Wellbore Cleanup Testing Right!
Authors: Fischer C. C. , Vining C. , Constien V.
Published: January 2016

Soft sand wells are typically more expensive completions due to the need for sand control. The sheer cost of the wells makes the completions more high risk and increases the need for laboratory testing to validate the screen or gravel pack sizing as well as drill-in fluid selection and filtercake cleanup.

Laboratory simulations of actual wellbore conditions to determine the effectiveness of wellbore cleanup treatments is quite complex. When the formation is unconsolidated and requires sand control such as screen only or gravel pack, the complexity increases further. Typical core flood equipment does not adequately confine the formation material to allow drilling and cleanup fluids to be circulated at representative shear rates and pressures over the formation face.

The paper summarizes over 15 years of work to develop procedures for dynamic drill-in fluid flow testing in a screen-only or gravel pack scenario. The suite of tests has been successfully used for multiple operators in order to determine the effects of drill-in fluids with unconsolidated and consolidated formation as well as to optimize clean-up treatment and gravel pack performance. This results in selection of least damaging drill-in fluids and better filtercake removal.

Dynamic flow cells have been designed to enable laboratory testing to be performed under matching wellbore conditions. This dynamic flow test method is unique because it has true slot flow that enables the filtercake to be deposited on the face of an unconsolidated formation pack. The well conditions are received from the client and the shear rate at the formation face is calculated and matched in the laboratory. Another unique aspect of the design is the ability to form the drill-in fluid filtercake on multiple test cells simultaneously.

Once the drill-in fluid filtercake is established, it is equally important to be able to simulate filtercake clean up treatments under laboratory conditions. The test method allows for multiple flushes across the filtercake to simulate the entire clean-up system. The flushes may include solids-free mud, push pill, clean oil or brine, and a reactive clean-up treatment, depending upon the drill-in fluid being tested. Multiple cleanup treatments can be applied to the filtercake, again matching the shear rate and temperature as indicated by the client well conditions. When a gravel pack is present, the cell design allows the gravel pack to be placed after the filtercake is built on the formation sand. Then, the clean-up treatment is circulated to the back side of the screen. The test method also allows for extended treatment soak times, up to 10 days.
Evaluating Damage to the Proppant Pack from Fracturing Fluids Prepared with Saline Water
Authors: Prabhu Rasika , Hutchins Richard , Makarychev-Mikhailov Sergey
Published: January 2016

Polymer gels used in hydraulic fracturing to generate fracture geometry and ensure proppant transport are also known to damage the proppant pack permeability, and this damage reduces the well production rate. As reuse of produced water and other highly saline water sources for fracturing applications grows, there is further damage expected from scale/precipitate deposition into the proppant pack. Past studies in the literature focus on impairment of proppant pack permeability from broken polymer gel residue, but precipitation of scale from source water is not considered. The objectives of this study are (i) to develop laboratory methods of assessing conductivity reduction from different fluid-based factors such as polymer residue and scale and (ii) to develop correlations to predict retained permeability based on simplified measurements. The simple methods will minimize the need for the standard conductivity testing, which can be time consuming, expensive, prone to significant test-to-test variation, and still subject to experimental artifacts. By the use of simplified procedures, the cost of conductivity testing can be reduced while allowing validation of the simplified method results.

We demonstrate a simple benchtop method to measure permeability of a proppant pack damaged by polymer residue, scale, or both. This method provides an opportunity to study a specific damage source in isolation, where the test is not influenced by problems such as spatial inhomogeneity of gel break, ineffective cleanup of filter cake, creation of proppant crush fines, etc., that are inherent in conventional API-type conductivity tests.

Experimental measurements of retained permeability arising from different sources such as polymer residue and scale were compared with traditional conductivity measurements. They were also correlated with empirical permeability models that rely on proppant pack porosity.

One key insight from the new, simplified method for proppant damage assessment is that the loss of permeability correlates with porosity reduction from polymer residue volume with a similar extension to scale precipitation.
An Assessment of an Uncomplicated Drill-in Fluid and Its Application to a Wide Range of Global Completions and Their Recent Successes
Authors: Luyster M. R. , Tresco K. , Dobson J. , Ravitz R. , Allogo C. M. , Lim K. Sooi
Published: January 2016

An established non-biopolymer reservoir drill-in (NBRDF) system which was developed in very early 2000 for high-density drilling applications – approximately 11.5 to 17.5 lbm/gal – was recently improved to provide functionality in low-density drilling applications – as low as 9.5 lbm/gal. Global implementation of this system over the last several years has demonstrated not only flexibility with respect to drilling and completing in diverse reservoirs but also its application as a workover system. In addition, this system was recently optimized by incorporating compatible chemistry to mitigate atypical damage mechanisms. As such, several case histories are presented to demonstrate the system's broad functionality with respect to density, completion type, reservoir, and logistics, as well as its capacity to reduce near-wellbore/formation damage.

This non-biopolymer reservoir drill-in fluid (NBRDF) system demonstrates relatively high tolerance to solids and reservoir fluids as well as ease of hydration when mixing on the rig. Routinely the hydraulics are consistent and predictable even as no biopolymer is utilized. This system is compatible with the incorporation of an inhibitor, specifically, a scale inhibitor to mitigate calcium carbonate and minor sulfate scaling. This system recently incorporated a sized calcinated magnesium compound (MC2) and sized magnesium complex (MC3) which promotes viscosity, specifically low-shear rate viscosity, at a lower density range that was not achievable before.

The initial concepts of buoyancy of solids and the exclusion of a biopolymer as incorporated in relatively high-density brines formed the basis for the development of this system. These concepts are discussed first to provide a background for the preceding recent improvements and case histories.

Each case history presents a different set of objectives whereby pre-planning assessments were implemented to address and mitigate perceived risks as related to the fluids. The methods employed include assessments for rheology, scaling, hydraulics, displacements, compatibility and formation damage. The drilling and completion results for these projects exhibit a wide range of applications as well as flexibility with respect to required density, completion hardware and reservoir type. The procedures utilized for each project are evaluated with respect to specific drilling and completion targets and include the iterations/modifications required; subsequently the field learnings are also discussed.