bluuebunny/crossref_metadata_2025_split huggingface dataset:
Restoring the Auca Field Potential Through Formation Damage Removal
Authors: Fun-Sang B. , Arévalo J. , Zamora P. , Grijalva R. , López Y. , Fraga R. , Pineiros S. , Mendoza A. , Carrión J. , Jiménez T. 
Published: January 2018

Abstract
The Auca field, located in the Amazonian region of Ecuador, started production in 1970, reaching a peak of 75,000 BOPD in March 2015. By the end of 2015, production declined to 65,000 BOPD due to water cut increase, reservoir pressure loss, and progressive formation damage. In January 2016, Petroamazonas EP (PAM) and Schlumberger (SLB) initiated the Shaya Project with the objective of increasing production and reserves through infill drilling, secondary recovery, and well interventions. The Auca field produces from the Hollín Formation and the Napo U and T sandstones. The latter two normally suffer from pressure depletion due to weak aquifer support, whereas the Hollín formation maintains reservoir pressure due a strong aquifer acting from the bottom. In general, formation damage in the Auca field is caused during drilling and pulling activities due to invasion of drilling or control fluids, but it also happens naturally in form of scale precipitation which has been physically proved, and possibly fines migration which remains a theory yet to be verified. Several workflows, procedures, and research on the nature of the damage have been put in place to resolve the production loss and decline issues associated with the varios potential causes. The selection of the most appropriate damage-removal technique depends on the reservoir and fluid properties, reservoir architecture, production behavior, water diagnosics, well intervention history, well geometry, artificial lift system, and, most importantly, the nature of the formation damage. From the reservoir and production engineering perspective, understanding formation damage and identifying its root cause is a key for designing the appropriate solution. After 18 months of intensive activity with drilling and workover operations, the production of the Auca field is close to 72,000 BOPD. If the operator had decided to stop activities, the production baseline would be at 35,000 BOPD. This means that, at present, the project has contributed a net incremental of 37,000 BOPD, of which approximately 30% corresponds to damage-removal jobs. This is a case study on one of the largest producing oilfields in the Oriente Basin that shows the typical productivity issues to deal with siliciclastic reservoirs and provides an example of how to select the most appropriate damage-removal techniques.
Systematic Laboratory and Modelling Study of Kaolinite in Rocks on Formation-Damage-Fines-Migration Non-Equilibrium Effects, Analytical Model
Authors: Russell Thomas , Chequer Larissa , Badalyan Alexander , Behr Aron , Genolet Luis , Kowollik Patrick , Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: January 2018

Abstract
The main objective of this work is to characterize the formation damage induced by fines migration in reservoir rocks with different kaolinite contents. The problem is particularly important for water production during oil and gas well operations, and for injectivity and sweep during low-salinity waterflooding.
We perform laboratory corefloods using aqueous solutions with different salinities in engineered rocks with different kaolinite content, yielding fines migration and permeability alteration. A novel methodology of preparing artificial sand-packs with a given kaolinite fraction has been established. Sequential injections of aqueous solutions in order of decreasing salinity were performed in five sand-packs with different kaolinite fractions varying from 1 to 10 weight percentage. Severe permeability decline was observed when deionized water was injected into the cores.
A new analytical model that captures the effects of fines release with delay and their re-entrapment by the rock has been developed. The new model allows for explicit expressions for the attached, suspended, and strained particle concentrations, as well as the pressure drop across the core. The analytical model shows good agreement with the laboratory-observed phenomena across a wide range of kaolinite concentrations. The model constants are presented for each of the five cores and lie within typically reported values.
The laboratory protocol and mathematical model allows for reliable prediction of fines-migration related formation-damage during waterflood, EOR, and commingled production of low-salinity water with oil or gas.
Improving Well Productivity of Tight Gas Reservoirs by Using Sodium Silicate in Water-Based Drill-in Fluid
Authors: Jafarov T. , Mahmoud M. , Al-Majed A. , Elkatatny S. , Bageri B. 
Published: January 2018

Abstract
The main objectives of this work are to prevent water blockage problem of wells drilled to tight gas reservoirs by minimizing fluid invasion and to reduce solid invasion with the optimized sodium silicate concentration in actual drill-in fluid and ultimately, improving well productivity by obtaining high return permeability after forming the very thin, impermeable and easily removable filter cake.
Static filtration tests were conducted on 0.25″ tight cores at 300°F under 300 psi ΔP with 250 psi back pressure and 500 psi inlet pressure to collect filtrate volumes. Rheology tests were performed up to 140°F under atmospheric and at 300°F under 300 psi pressure. Rheology experiments were performed for base fluid and with 0.05, 0.075, 0.1 wt%, while filtrations were also performed for 0.5, 1 and 1.5 wt% sodium silicate concentrations. Initial and return permeabilities were measured by injecting 3 wt% KCl through 2″ core sample under constant flow rates after damaging it. CT numbers were obtained before and after damaging 2″ core by doing CT Scan.
Filtrate volume and cake thickness reduced by 53% and 65% with 0.075 wt% (3.5 ml & 0.7 mm), respectively, compared than base fluid (7.4 ml & 2 mm). 0.075 wt% determined as an optimum concentration. Water blockage problem of tight gas wells prevented by minimizing the fluid invasion. Measured initial and return permeabilities of 2″ core remained same as 1.3 mD. This result proved that no solid invasion occurs with 0.075 wt% sodium silicate and in case of 100% filter cake removal, return permeability will be 100%. Forming filter cake with 0.7 mm thickness lets us to claim that it can be completely removed by washing with 15 wt% HCl. Obtained CT numbers confirmed return permeability measurement as well.
Barite flotation recovery and solubility concentration of silica with PH are the two approaches that should be considered together to explain the mechanism of 0.075 wt% sodium silicate. Polymerization effect shows itself for ≤0.075 wt%, while amorphous silica effect occurs for &gt;0.075 wt%. Polymerization effect became the evidence of obtaining 100% return permeability.
Chelate Based Acidizing Fluid Provides HSE Advantages in Successful North Sea Application
Authors: Santos A. Dos , Oliveira E. , Stanitzek T. , Hoq A. , Doghmi A. 
Published: January 2018

Abstract
Matrix stimulation is commonly utilized to increase well productivity and it is a process in which fluid selection plays a key role in treatment success. However, in offshore fields, the acid formulation must not only be effective in damage removal but it also has to meet stricter HSE regulations while safeguarding expensive and complex installations from corrosion impact. In high temperature environments or where sensitive metallurgy is deployed, higher doses of corrosion inhibitors are required as well as additional additives in order to avoid unwanted reactions, further complicating the handling and HSE aspects of such acids.
The environmentally friendly chelate, glutamic acid N,N-diacetic acid GLDA, has been examined as an alternative for acidizing and descaling treatments, demonstrating good field performance in terms of productivity and injectivity increase. All this achieved while providing a safe and convenient system for handling, due its low toxicity, fewer required additives and biodegradability. Numerous laboratory tests have measured and confirmed considerably less corrosion risk, across a wide range of conditions, when compared to conventional formulations based on both HCl and organic acids. Within this paper, the field performance of the GLDA system will be evaluated under even more challenging conditions, endured during the acidizing of an offshore well in the North Sea.
The wellwork programme for the low rate gas producer consisted of performing two new perforation runs, followed by the injection of the GLDA treatment, which was then bullheaded into the formation with a nitrogen assist. The treatment formulation consisted of GLDA diluted in fresh water with trace amounts of surfactant and mutual solvent to aid in the flow-back of the spent acid.
Due to an unexpected power failure on the platform, the treatment remained stagnant in the tubing for some 28 hrs at 300°F. As this was the first GLDA treatment in this field, this situation appropriately raised potential well integrity concerns; as would most certainly have been the case with a conventional HCl acid package. However, once the operation was restarted the acid was successfully bullheaded into the formation and no issues resulted with the low carbon and CRA based metallurgy of the completion even after this extensive unplanned exposure. Additionally the treatment resulted in a significant productivity increase.
These operations and results demonstrated not only the gentle nature of GLDA for integrity considerations; but also an effective cleanout of perforations and near wellbore area as required from a replacement system. The success of the treatment proved the intrinsic value and reduced risk that can be accessed by use of such systems.
Improving Well Injectivity by Surfactant Flushing - A Digital Rock Study
Authors: Bautista J. F. , Xu R. , Fager A. , Crouse B. , Freed D. 
Published: January 2018

Abstract
There are many causes for injection wells to perform poorly; in this paper, we address the effect of residual hydrocarbons near the wellbore, which reduce the rock's effective permeability to brine, thus decreasing well injectivity. Immobile hydrocarbon saturations are found around injection wells when these are drilled above the water-oil contact level, which arises when a producer well is switched to injection, or the formation's underlying aquifer is hard to reach. Furthermore, oil can accumulate around a wellbore when produced brine containing even trace amounts of hydrocarbons is used as the injection fluid. To address this problem, it is possible to flush out hydrocarbons around the wellbore by periodically injecting small amounts of surfactants for short periods. This technique leverages the capillary desaturation behavior of a multi-phase fluid mixture, wherein increasing the capillary number of a rock-fluids system beyond a threshold value will decrease the residual hydrocarbon saturation. The capillary number, which characterizes the ratio of viscous to capillary forces, can be increased by injecting surfactant loaded brine; this reduces the hydrocarbon-brine interfacial tension which reduces the capillary forces, decreases the system's residual hydrocarbon saturation, and increases the brine's effective permeability. To efficiently assess the impact of a surfactant flush, we perform digital rock multi-phase flow simulations on Berea and Fontainebleau sandstones at different capillary numbers. The simulations provide the residual hydrocarbon saturation and the brine's effective permeability as a function of capillary number, which is related to the amount and type of surfactant. These results are then used in a radial wellbore simulation to compute the attainable injection rate for a maximum allowable pressure drop. Since the largest pressure drop occurs very close to the wellbore, the surfactant flush is very effective even though it only affects a few feet from the wellbore. For the specified scenario we observe a potential well performance improvement ranging between 20% and 150%. By using digital methods, this study was performed in about two weeks, at lower cost than Special Core Analysis Laboratory (SCAL) physical testing, and with ideal reproducibilty since the capillary number can be modified without affecting the sample or any other aspect of the test procedure.
Effect of Fracturing Chemicals on Well Productivity: Avoiding Pitfalls in Big Data Analysis
Authors: Khvostichenko Daria , Makarychev-Mikhailov Sergey 
Published: January 2018

Abstract
A statistically rigorous assessment of the effect of fracturing treatment chemical additives on well productivity was performed. The dataset for analysis consisted of over 4,500 slickwater-treated wells in the lower 48 US states. All wells were treated by a single service company within a 5-year period. The analysis focused on two distinct additives, namely, linear guar gels and surfactant-based flowback aids, in slickwater treatments. A method and workflow to quantify the effects of completion parameters on well productivity were developed in this work. The statistical t-test was used to assess the statistical significance of differences in aggregated production metrics between datasets based on the observation that production data were distributed log-normally. The proposed workflow addresses many common issues a reservoir engineer faces during data sourcing, preprocessing, evaluation, and interpretation and further highlights the importance of proper statistical approaches. The analysis results emphasize the benefits of proper job design even in relatively simple slickwater treatments.
Lowering Fresh Water Usage in Hydraulic Fracturing by Stabilizing scCO2 Foam with Polyelectrolyte Complex Nanoparticles Prepared in High Salinity Produced Water
Authors: Hosseini H. , Tsau J. , Peltier E. , Barati R. 
Published: January 2018

Abstract
Polyelectrolyte complex nanoparticle (PECNP) systems compatible with produced water were developed to improve supercritical CO2 (scCO2) foam stability and to reduce fluid loss for fracturing applications. Foam viscosity, stability, fluid loss properties and cleanup of injected liquid through the formation were enhanced by PECNP-surfactant systems prepared in produced water medium. Taking advantage of produced water as energized fluids for fracturing requires enhanced compatibility of gas/liquid mixture. Two produced water recipes of 33,333 and 66,666ppm TDS were used to prepare 1 w/w% surfactant solutions. PECNP was formed as a mixture of positively- and negatively- charged polyelectrolytes. Experimental setup was designed to determine the aqueous foam stability at actual reservoir conditions. Rheological measurement was performed to measure the stability of the bulk foam under shear and to evaluate the foam texture properties. The improved viscosity of different proportions of PECNP-Surfactant (9:1, 8:2, 7:3, and 6:4) in aqueous foam mixtures was observed as compared to surfactant stabilized CO2 foam. The flow consistency index observed in the shear thinning region was also increased from 1184.3 to 2916.4 Pa sn in 33,333ppm and from 1035.7 to 1683.1 Pa snin 66,666ppm brine solutions. The view cell results revealed the high stability and longevity of scCO2 foam employing various proportions of surfactant to nanoparticle as oppose to surfactant generated foam in which the foam height shortened faster. The presented scCO2 generated foam can preserve the foam cellular structure in absence of crude oil. The PECNP-Surfactant system successfully lowered the interfacial tension to up to 74% and 93% for 33,333 and 66,666ppm brine salinity, respectively. Fluid loss was measured to evaluate fluid leak-off from a core when the high flow velocity along the core exists. The fluid loss for both CO2 and water leak-off were also lowered employing PECNP- Surfactant containing foam.
A Large-Scale Sand Retention Test Facility for Evaluation and Selection of Optimal Standalone Sand Screen for Injection Wells in Thermal Operations
Authors: Mahmoudi M. , Fattahpour V. , Wang C. , Kotb O. , Roostaei M. , Nouri A. , Fermaniuk B. , Sauve A. , Sutton C. 
Published: January 2018

Abstract
Sand production is not usually considered a major concern during the injection phase in injection wells. However, well shut-in for service requirements or sudden pump failure, hence the backflow towards the wellbore and potential generation of water hammer pressure pulsing, can lead to massive sand production under favorable conditions. With the aim of sanding prevention, this paper examines the design criteria for standalone screens (SAS) in injection wells using a novel sand control testing facility.
This paper presents a new large-scale sand retention testing (SRT) facility to simulate the effect of pressure pulsation and backflow in injection wells on the sand control performance of SAS. The SRT facility can be used in the selection of the best sand control method for injector wells. It can be also used to provide further understanding on the impact of formation damage on well injectivity decline, as well as study the effect of water hammer pressure pulsation on sand production in injection wells.
Test results show a rapid fall off in the pressure and drastically high backflow rates due to the sudden shut-in. Higher pressure drops are observed to result in a greater backflow volume and a longer backflow period. Results also show that the slot width has a drastic influence on the sanding performance of the screen. Testing observations, for the studied PSD, indicate that the injection well requires narrower slots 1.4 D10 to meet the sand production requirements due to a high fluidization potential in the near-screen zone. Higher flow velocities during the backflow period and the tossing effect caused by the pressure waves increase the sanding potential. The produced sand during the backflow period, is observed to mainly relate to the ratio of the slot width to the mean formation grain size. It is observed that higher effective stresses around the screen work towards stabilizing the sand bridges and reducing the amount of produced sand.
This paper presents a new experimental test facility for the sand control type selection and evaluation for injection wells with the aim of limiting the amount of produced sand and sustaining the wellbore injectivity. The proposed testing facility allows the performance comparison of different sand control devices and designs.
Formation Damage Circumvent in HP-HT due to Pore Pressure Regression
Authors: Shaker Selim S. 
Published: January 2018

Abstract
One of the main causes involved in reservoir formation damages is the excessive mud filtrate during drilling with an overbalanced mud weight. Results show reservoir pressure retreat due to geological structural failure can leads to a large disparity between MW and PP especially in HPHT environment.
This new approach focuses on the geological structural failure that causes the well bore trajectory to cut through different transgressive and regressive pressure envelops. If the mud program, based on the pre-drill pore pressure model, did not account for a pressure retreat, a sizeable lost circulation can take place. Mud fluid invasion to the open borehole wall can decrease permeability, impact logs measurements and potential production. Moreover, thick mud cake causes bore-hole tight spots, excessive torques and pulls. Incorporating the subsurface geological structure features to the seismic driven pre-drilling models can foresee the unexpected mud weight overbalance intervals.
In relative old sediments, such as Oligocene and Miocene in the offshore shelf areas, a substantial mud weight (MW) increase of 2-5 ponds is needed to penetrate the top of geopressure (TOG). The deeper geopressured compartments are usually drilled with MW that sometimes reaches 18 pounds per gallon. Moreover, temperature can range from 300 to 350 degrees Fahrenheit. Formation damages and serious challenges take place where the MW is overbalance juxtaposing a regressive permeable rock sequence. Study the relationship between geopressure compartmentalization and drilling challenges of multiple wells in East – West Cameron, offshore Louisiana sheds light on one of the important causes of formation damages, tight spots, high torque and pulls. Pay zones were partially masked due to deep mud filtrate invasion with frequent use of oil-base to reduce pulls in the tight spots. Sidetracks usually was the ultimate remedy for some of the wells that did not reach their objective TD. The case histories shown in this study illustrate that exploring the depth to the possible regression zones before drilling in conjunction with the pre-drill pore pressure model could have alerted drillers for MW amendment to avoid lost circulation.
The benefit of correlating the bore-hole trajectory to the seismic semblance associated with the geopressure profile is a resourceful method of foreseeing the troublesome intervals. In real time, calibrating the MW derived from the seismic pre-drill model is another deterrent process to avoid utilizing excessive overbalanced MW.
High-Temperature Viscoelastic Surfactant Fluids with Low Scaling Tendency and Based on Seawater, Produced Water, or Brines
Authors: Li Leiming , Liang Feng 
Published: January 2018

Abstract
The viscoelastic surfactant (VES) fluids have been widely used in oilfield operations due to their advantages over polymer-based linear or crosslinked fluids that include low formation damage, good proppant suspending and carrying ability, strong tolerance to low-quality water, to name a few. Most of the conventional VES fluid systems, however, have upper temperature limits at around 250°F, beyond which the fluid performance and stability quickly deteriorate.
In this paper, a new type of VES fluids formulated with seawater, produced water, or brines showed excellent performances at 350°F or higher, while at the same time had low scaling tendency upon mixing with high-TDS formation water downhole. To reduce the chemical cost of the new VES fluids, a number of novel and low-cost additives were successfully identified that significantly increased the fluid viscosity at elevated temperatures, resulting in similar or better fluid performances with reduced dosages of the VES molecules.
The selected VES-enhancing additives strengthened the VES fluids formulated with various sources of water including low-quality water like seawater or produced water at high temperatures up to 350°F or more. In one example, when additive-I was added at the dosage of about 0.8% by weight, the VES fluid viscosity was enhanced by about 35% on average between 300 and 350°F. At 350°F, the viscosity enhancement was about 50% with the same loading of additive-I. The overall cost of the additive-I applied was below 3% that of the baseline VES fluid. In another case, compared with the baseline VES fluid, additive-II at the dosage of about 0.8% by weight raised the fluid viscosity at 350°F to over four times. The cost of the additive-II used in the case was also trivial when compared with that of the baseline fluid. The fluid viscosity could also be enhanced when a number of other selected additives were added to the VES fluids at appropriate dosages. The additive-enhanced VES fluids, in the meantime, caused only minimal damage to the formation, as the regained permeability was about 90%.
The novel VES-enhancing additives might have, through van der Waals forces, simultaneously attached to multiple VES micelles in the fluids, thus strengthening the three-dimensional network of the VES micelles. This way, the overall fluid viscosity could be increased. Further discussions about the enhancing behaviors and mechanisms of the selected additives in the VES fluids formulated with seawater, produced water, or brines, and the laboratory test results will be presented in detail.