bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Approach to Gel Breakers for Hydraulic Fracturing
Authors: Fuller Michael J. 
Published: January 2016

Abstract
Gelled fluids are routinely used in hydraulic fracturing to deliver fractures with higher propped width, due to the fluids' abilities to deliver higher proppant concentrations than their lower-viscosity analogues. The most common of these gels (borate-crosslinked polymers) have been used successfully in fracturing for decades, routinely exhibiting viscosity &gt;100cP in conventional high-pressure, high temperature (HPHT) viscosity measurements. Recent studies have found that the viscosities of borate gels at actual downhole pressure conditions may be 80% less than that measured using standard HPHT rheometer measurement (which uses 400 psi top-pressure). A proposed mechanism for this phenomenon is a pressure-induced shifting of the crosslink/temperature stability near the "melt temperature" of borate-crosslinked gels, leading to a reversible thinning. A novel approach is posed in the current work to exploit the "pressure effect", by capturing the pressure-thinned fluid in a thin state and irreversibly breaking the gel viscosity.
As existing crosslinked-gels with oxidative breakers rarely achieve &gt;50% retained pack-permeability, an improved break mechanism based on pressure could yield sizeable productivity-gain in propped fractures. A series of candidate breaker materials with potential affinity for the crosslinker was screened for gel-breaking performance in the current work. Preliminary screening of these additives led to one preferred alternative gel breaker material which demonstrated superior performance in pressure-induced breaking behavior. This study will illustrate advanced characterization of the breaker performance utilizing realistic sequences of temperature, pressure and shear rate that would be expected for a fracturing treatment. The advanced characterization also included fracture-conductivity measurements comparing a control gel with and without the alternative breaker.
Under these conditions, the fluids containing the candidate breaker material showed persistent viscosity-break, while the control fluids recovered their viscosities upon pressure-release. The preferred breaker material performance was further confirmed through a series of experimental conditions varying temperature, pressure (up to 10,000 psi), gel concentration, and breaker concentration. In fracture conductivity measurements, the gel which contained the preferred breaker also showed improved conductivity compared to control fluids without breaker.
The current study proposes a new method of achieving break of gelled fracturing fluid, which avoids some of the risks and disadvantages of oxidizer chemicals. These results will suggest the most preferred fluid conditions for applying the new breaker material in hydraulic fracturing.
Removing Formation Damage From Fines Migration in the Putumayo Basin in Colombia: Challenges, Results, Lessons Learned, and New Opportunities after More Than 100 Sandstone Acidizing Treatments
Authors: Reinoso Wildiman , Torres Fredy , Aldana Manuel , Campo Pablo , Alvarez Emilce , Tovar Erika 
Published: January 2016

Abstract
This paper summarizes a wide variety of sandstone acid stimulation case histories, highlighting different aspects, such as mechanical conditions and operational practices. These include injection sequence changes, injectivity factor calculations, treatment volumes, quality control during pumping, pressure response, and the influence of each on treatment performance.
To date, more than 100 sandstone acidizing treatments have been performed in several Colombian oil fields, targeting the Villeta and Caballos formations in the Putumayo basin. Fines migration has been the main damage mechanism treated with this type of chemical stimulation. Three main steps were performed when sandstone acidizing treatments were conducted: preflush, primary treatment, and post-flush. A fines-control retarded hydrofluoric (HF) acid system was selected as the primary acid system. This retarded system removes deep damage caused by fines and swelling clays and helps prevent fines migration.
Challenges, results, lessons learned, and new opportunities from the understanding of theoretical aspects, acid-removable skin analysis, and integration of coreflooding tests with computer simulations as well as post-treatment results showing several-fold increases in oil productivity are presented in this paper. Treatments developed in reservoirs with a temperature of 180°F, as well as use of scale inhibitors and treatments assisted with relative permeability modifiers (RPMs) to control water production, are discussed. Also, results of testing with a biodegradable chelating agent that could provide an alternative treatment for some scenarios are presented. The aminopolycarboxylic acid (as described by Reyes et al. 2013) used is soluble in a low-pH aqueous medium and is compatible with HF acid.
The step-by-step procedures identify the parameters that have the most influence on treatment performance and provided outstanding results. The resulting lessons learned can be applied for future applications in many more candidate wells with similar conditions.
Effective Resin Consolidation Treatment Methods and Compositions for Clay-Laden Formations
Authors: Rama Mallikarjuna Shroff , Songire Sumit , Meher Pratiksha , Kristanto Tutus Agung , Latief Riyanto , bin Zulkapli Mohd 
Published: January 2016

Abstract
Resin consolidation of the near-wellbore (NWB) region is often performed to control sand production. However, when the formation is composed of a higher content of clays and fines, particularly when the swellable clay content is higher than 4%, it can be challenging to treat the formation and obtain good consolidation with acceptable retained permeability. Possible reasons for this include: 1) smaller grain size and smaller pore throats can hinder any resin coating, affecting the retained permeability and 2) the resin can enter into the interlayer and swell the clays infinitely, eventually blocking the pore throats.
Improved methods to provide consolidation to clay-laden formations are described based on laboratory testing and analysis. The effects of various treatment methods, such as using clay-control agents during the preflush stage of the resin treatment and reducing the viscosity of the resin treatment fluid to obtain optimum consolidation and retained permeability, are discussed.
The present method uses cationic organic polymers (COPs) in the preflush that can control swelling clays followed by less-viscous resin treatment fluid, which can form a thinner coating around grains and provide acceptable strength without significantly compromising regain permeability.
Laboratory testing was performed on various formation sands having higher clay content, 5 to 10%, combined with fines ranging from 5 to 15%. The results showed that traditional resin consolidation treatments do not provide acceptable retained permeability and consolidation strength. Using COPs in the preflush provided improved retained permeability. Using a combination of COPs in the preflush and a diluted resin treatment provided significantly improved results. This shows that COPs help prevent clays from swelling. The resin cannot enter the interlayer and swell clays any further, thus improving retained permeability. Additionally, when the treatment fluid is diluted, it can penetrate uniformly throughout a sandpack, providing a thinner but sufficient coating of the resin to achieve good consolidation and also good retained permeability.
A novel method and composition for a resin consolidation service to obtain effective consolidation strength and acceptable retained permeability in clay-laden formations is demonstrated by means of laboratory testing of the actual formation sand.
Previously, it was impossible to consolidate a formation that possesses large amounts of fines and clays while maintaining retained permeability in an acceptable range. This new method is applicable in the field without requiring additional tools or more stages during the treatment procedure.
Perforating Large High-Pressure Wells with Low-Shock and Low-Debris Gun Systems
Authors: Baumann C. E. , Smart M. E. , Stulb C. , Brinsden M. S. , Gavric Z. , Le C. V. 
Published: January 2016

Abstract
Many large wells have been drilled in the Gulf of Mexico's Lower Tertiary play. These wells are completed with single-trip multizone systems, and they have gross perforated lengths exceeding 1,500 ft. The main difficulty in perforating these wells is the high-pressure environment (~20,000 psi). Under these conditions, the challenges are to create sufficiently large entrance holes in the casing, minimize the high-risk of equipment damage due to gunshock, and minimize the amount of perforating debris created.
Perforating several intervals in a single run is required to complement single-trip multizone systems. Perforating all zones simultaneously in one trip saves time and reduces risks when compared with stacked completions requiring multiple trips for each zone. Safety and cost reduction are extremely important in deepwater operations. Risk control is very important because gunshock and/or debris problems can lead to multimillion dollar losses in non-productive time, and in extreme cases, gunshock problems can lead to lost wells.
To undertake these challenges, a new Low Perforating Shock and Debris (LPSD) gun system was used. In comparison with standard high-pressure guns, the LPSD gun system produces much less gunshock and negligible amounts of debris; thus, minimizing gunshock risk and reducing cleanup runs typically needed to recover perforating debris. LPSD guns produce negligible amounts of debris because LPSD guns contain all the metallic components, including the shaped charge cases, which remain virtually intact inside of the guns. A key element in planning these perforating jobs is gunshock prediction to evaluate if the equipment will be able to withstand the transient loads produced by the perforating guns. The gunshock prediction process is described in detail in this paper.
For a typical 4-zone 1,500 ft gross length perforating job, the time needed from picking up the first gun to laying out the last gun averages 84 hours. All zones are simultaneously perforated, which eliminates three perforating runs per well, saving approximately 9.2 days per well while minimizing personnel exposure. By perforating the largest high-pressure wells in the Gulf of Mexico's Lower-Tertiary play with LPSD guns, we minimized personnel exposure, minimized debris and reduced execution time up to 72%.
Applied Buildup Well Test Interpretation: Field Testing of Conventional and Deconvolution Methods
Authors: Rosario Omar , Martinez Mauro , Baumann Carlos , Ardila Mario 
Published: January 2016

Abstract
Well tests are typically used to evaluate formation damage before and after workovers. Buildup tests are the most commonly used transient because less flow rate measurement uncertainties leading in more reliable results, and they have a robust mathematical foundation. To take in account the flow rate history and its uncertainties several deconvolution algorithms were developed. These algorithms also are applicable to minimize the initial distortion in the reservoir's pressure response due to wellbore storage, with the expectation of improving the permeability and total skin estimated in shorter logging times.
This paper presents a comparative study of conventional well test methods, and direct and indirect deconvolution techniques in several field cases. This study includes buildup tests of real-time sandface rate measurements during the after-flow period. These field cases were analyzed using conventional well test methods and three deconvolution techniques; namely, straight line approximation, material balance deconvolution, and modified "β" function.
We determined that the three deconvolution methods are preferable to conventional well test methods because they require much shorter logging times; however, their reliability depends on the real-time data acquisition quality.
The well tests analyzed show that we cannot rely solely on the new deconvolution techniques for well test interpretation in shorter times; however, these new methods improve the reliability in the main matching parameters, permeability and total skin, at no additional time and cost. As a result, the new methods are excellent additions to the techniques used for well test interpretation.
Novel Perforation and Stimulation Approach to Maximize Production from HPHT Sour Gas Wells: Kuwait Jurassic Best Practices
Authors: Pradhan San P. , Al-Otaibi Yousef M. , Al-Mutairi Abdullah B. , Mahmoud Wael , Abdelbagi Mamoun. E. , Slama Hedi 
Published: January 2016

Abstract
Optimized perforation and stimulation approach was developed to maximize production and overcome heavy oil based mud (OBM) associated damage for HPHT condensate wells (matrix-dominated flow) from Jurassic formation in Kuwait. This paper shares the challenges, approach and results of this novel methodology that led to significant production enhancement.
Heavy OBM is the drilling and completion fluid for deep carbonate formation of Jurassic era reservoirs in Kuwait. Conventional tubing conveyed perforation (TCP)/Wireline perforation requires well killing to run final completion. Production tests carried out before and after running final completion showed significant drop in production of hydrocarbon. Conventional coil tubing acid jobs was performed to bypass the damage but still production was well below expectations. After analyzing pros and cons of multiple perforation and completion methodologies, finally gun hanger shoot and drop perforation system was re-introduced for Jurassic wells.
Robust design and completion process was developed for successful execution as previous attempts of gun hanger shoot and drop system was not successful due to extreme environment (16,000 ft Depth, 11,500 psi Reservoir Pressure, 4% H2S, 3% CO2). Successful execution using gun hanger shoot and drop system with ‘just in time’ firing facilitated underbalanced perforation with immediate production tests and no requirement of further killing of well. Engineered perforation and gun design helped in optimizing space available below zone of interest for any well intervention activities. Initial well tests showed encouraging production result with significant oil and gas flow. Thick walled coil tubing was successfully deployed in live well to perform well activation in extreme environment to bypass formation damage caused during drilling process and improved acid placement. Combination of acid and produced hydrocarbon led to In-situ generation of emulsified acid providing deeper penetration of acid. Acid pumping rate and pressure was optimized to generate conductive acid etched channels and avoid creation of inefficient fractures. Cross-segment collaboration led to successful execution in challenging conditions leading to five-fold increase in production post stimulation.
Gun hanger shoot and drop system was successfully re-introduced for underbalanced perforation in extreme Jurassic environment. Coil tubing operation was performed for the first time in a live Jurassic well with bottom hole pressure close to 15,000 psi and H2S close to 4%.
Minimize Formation Damage in Water-Sensitive Unconventional Reservoirs by Using Energized Fracturing Fluid
Authors: Kong Bing , Wang Shuhua , Chen Shengnan , Dong Kai 
Published: January 2016

Abstract
Slickwater has been widely used for hydraulic fracturing as it is inexpensive and able to carry proppants into the fracture. However, such fluid is unsuitable for water-sensitive formations, such as Montney. Water saturation around the fracture increases and clay swells when water leaks-off into matrix, both hindering natural gas flowing from matrix into fractures. N2 or CO2 energized water-based fracturing fluids have been widely used in water-sensitive formation as they can minimize fluid leak off during fracturing and achieve higher load fluid recovery during flow back.
In this paper, multi-phase numerical simulations are applied to study the formation damage mitigation in Montney tight reservoir by using energized fracturing fluid. A simulation model is built and history matched with flow back and early production data of a typical Montney tight gas well. The behavior of multi-phase fluid leak off and flow back is studied, and the sensitivity of foam quality of fracturing fluid on load fluid recovery and well after stimulation productivity is analyzed. Statistical analysis is conducted on the stimulation and production data of over 5000 Montney wells to study the performance of energized fracturing in water-sensitive Montney formation. It is found that multi-phase fracturing fluid has less dynamic fluid leak off than that of a single phase fracturing fluid (i.e., water), and the major fluid leak off occurs during the static leak off period between the end of the stimulation processes and start of the flow back. Gas phase penetrates deeper and faster into the reservoir matrix in comparison with the liquid phase, which greatly contributes to flow back of fracturing fluid. Formation damage caused by fracturing fluid leak off can affect both early and long term production. In addition, N2-foam leads to the highest load fluid recovery in Montney formation, which is 1.6 times of that of CO2-foam. This work provides critical insights into understanding the performance of using energized fracturing fluid to mitigate formation damage in tight formations.
Identifying the Source and Magnitude of Formation Damage from Pressure and Temperature Profiles
Authors: You Z. , Bedrikovetsky P. 
Published: January 2016

Abstract
Evaluation of flow rate profile along the wellbore is very important for reservoir characterization, because it indicates the contribution of each inflow point at different depth to the overall production rate. The temperature and pressure sensors in the wellbore are small and cheap, whereas flow meters are cumbersome and expensive, and affect the flow in the well. The method presented in the current paper shows its significance in predicting the gas rate from temperature and pressure data. A mathematical model for pressure and temperature distributions along gas well has been developed. Temperature and pressure profiles from nine well intervals in field C (Australia) have been matched with the mathematical model to determine the flow rates from different layers in the well. The present model considers the variables as functions of thermal properties at each depth, which is more accurate if compared to previous models. Results of tuning the mathematical model to field data show good agreement with the model prediction. Simple and explicit formulae are derived for effective evaluation of flow rate and thermal conductivity in gas wells. The proposed approach has been applied to the estimation of gas rates and formation thermal conductivities from the measured well pressure and temperature data in field C. It provides useful information for identifying the source and magnitude of formation damage and recommending well stimulation of the layers with low rates.
A New Phenomenon of Slow Fines Migration in Oil and Gas Fields (Laboratory and Mathematical Modelling)
Authors: Yang Y. , You Z. , Siqueira F. D. , Vaz A. , Bedrikovetsky P. 
Published: January 2016

Abstract
Fines migration causes significant permeability damage, due to mobilisation of particles at increased velocities, their migration in pores followed by straining at pore throats and attachment to pore walls. Numerous coreflooding tests with piecewise increasing rates are conducted. There are two main features of these tests: the first is long-term injection, which allows calculating permeability stabilisation time; the second is pressure measurement at intermediate points, allowing for evaluating the permeability profile along the core. The impedance data obtained from experiments are matched with the results from analytical model. It shows that the mobilised particles move with velocity much smaller than the carrier fluid, yielding long time for permeability stabilisation. It contradicts the classical filtration theory, which indicates the fines are transported with the carrier fluid velocity.
A New Method for Water Shut-Off Using Induced Formation Damage
Authors: Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: January 2016

Abstract
A common problem in aquifer water-drive reservoirs and water flooding projects is premature and excessive water production through natural fractures, faults or high permeable thief zones. The most common water shut-off methods today is polymer gel treatment; however, a large treatment volume is required to block the water influx that generally involves high operational, material and environmental costs.
It is well known that injection of low salinity water into a reservoir that contains movable clays can significantly decrease the rock permeability. This paper presents a new technique of applying induced formation damage for water shut-off in order to block the water influx from high permeable water producing layers. This study applies numerical simulation to investigate the effectiveness of the induced formation damage treatment for reducing water production. The results of the study show that injection of an small slug (~1% PVI) of low salinity water into the water producing well resulted in ~30% reduction in produced water cut and ~6% incremental recovery.
Delivering A More Consistent Estimation of Tight Rock Permeability
Authors: Ling Kegang , Feng Yin , Ghalambor Ali , Zhou Lijun , He Jun 
Published: January 2016

Abstract
Petroleum exploration and production from the tight reservoirs such as shale have gained great success in United States during last decade. Producing hydrocarbons from shale is challenging due to its low matrix permeability. It is therefore, crucial to investigate shale permeability to better understand the performance of unconventional resources wells. In addition, permeability is not only one of the key parameters in modeling fluids flow in matrix in reservoir simulation, but also a key parameter regulating production decline rate, which is critical to the stimulation process and to the economics of well. Since the inference of shale permeability is time consuming and expensive due to its low range of permeability, Gas Research Institute (GRI) method is applied as a shortcut. Unfortunately, many studies have pointed out that there is significant variation in the results reported by different laboratories using the GRI technique. It is difficult to identify that whether the differences are due to apparatus or the interpretation method, since GRI report did not provide a detailed description for interpreting the raw data. Furthermore, there is no available theoretical base in the literatures for the GRI technique. Due to the high uncertainty in the GRI method, it is worth to develop the theoretical basis for this technique. In this study, starting from the basic physics laws, we derived the governing equation for the fluid transient flow behavior in the GRI permeability measurement. The rigorous derivation provides a solid foundation for analyzing experimental data. The interpretation of test data can be more reliable through solving the governing equations either analytically or numerically. In this way, we can increase the agreement of the results from different laboratories using GRI technique. A case study is used to compare the developed mathematical model with literature data. The differences may be caused by the deviation from the assumptions in developing the theoretical model. Considering the non-spherical particles and non-uniform sizes of particles involved in the experiment, the multi-variable regression proposed in this study makes the analysis of GRI permeability data more practical and reasonable. In order to reduce the interpretation uncertainty, multiple reference cell pressures are used to measure the same crushed sample and generate corresponding pressure-decay curves. The proposed equation will allow engineers to interpret experimental data in a more practical and reasonable way.