bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study of the Permeability Damage Associated with Fines Production from a Bituminous Coal during Water Injection
Authors: Guo Zhenghuai , Hussain Furqan , Cinar Yildiray 
Published: May 2015

Abstract
Coal seam gas (CSG) production involves water flow through coal cleats. Creep effect and fines migration can cause a severe damage to coal permeability during water flow. This study presents a systematic methodology to analyze coupled effect of creep and fines migration in a water injection test in a coal sample. Previous studies investigating permeability changes in coal during water flow do not incorporate both of these effects.
We perform two flow tests on coal samples from a mine in China. Proximate, petrographic and XRD tests were conducted for a robust characterization of the coal sample. The coal samples are saturated with ultra-pure water. Afterwards, the same water is injected through the saturated coal sample. The test temperature and injection pressure was kept constant during the flow and production rate was measured continuously to calculate permeability. Fines concentration of the produced water samples was tested by a laser particle counter. Afterwards, the produced fines were separated from the water samples using micron membrane filters. The separated fines were then analyzed using SEM-EDX method. The only difference in two tests procedure is that in first test, the sample is mounted in a Hasseler coreholder under 300psi confining stress while the second test is done under zero confining stress. This allows us to remove any creep effects in the 2nd test while the first test results are affected by both creep effect and fines migration.
The samples in this study are characterized to be bituminous coal containing mainly kaolinite and dolomite in mineral matters. The permeability is reduced to 10% and 73% of the original value in the first and second test, respectively. Although, creep effect is more pronounced as compared to fines migration effect, the 2nd flow test results demonstrate significant permeability damage during the water injection through the coal samples, along with appreciable fines production. The produced fines appear mainly in form of a mixture of coal and clay minerals. The strain associated with the creep effect in the first test contributes to a relatively high fines production as compared to the second test.
New Innovative Process for Underbalanced Drilling Candidate Screening
Authors: Qutob Hani , Byrne Micheal 
Published: May 2015

Abstract
Underbalanced drilling technology (UBD) has increased production potential from many oil and gas reservoirs worldwide. When UBD succeeds, it works wonders; Discovering hidden production zones, improving drilling by eliminating lost circulation and differential sticking, increasing rate of penetration, improving production by reducing formation damage, and providing real time reservoir evaluation. The result is Enhanced Oil Recovery and Improved Net Present Value.
Yet too often, UBD fails to live up to its potential either because unsuitable reservoirs are drilled or inappropriate drilling technology is applied. The key to selecting appropriate reservoir candidates for UBD is achieving a balance of technical, safety and economic factors.
Recognizing the growing need for better predictive tools to drive improved outcomes, an expert system was developed. The system is a process that uses Computational Fluid Dynamics (CFD) to enable detailed modeling of fluids in wells and the surrounding reservoirs. CFD is the study of the dynamics of things that flow.
The use of the expert system to screen and select candidate reservoirs for the UBD and MPD applications enables accurate prediction using detailed numerical models of flow in the reservoir, damaged zone and the wellbore. These predictions reveal the actual benefits of Underbalanced and Managed Pressure Drilling in well productivity and increased well recovery through the reduction of formation damage.
This innovative expert system has been used in more than 40 projects for some of the world's leading oil and gas projects across UK, Western and Eastern Europe, Scandinavia, Middle East and Asia. Users of this system recognize that near wellbore fluid flow modeling using CFD will become standard industry practice. This paper describes in detail the expert system and presents the successful application and several case histories and real results.
Formation Damage in Tight Gas Reservoirs
Authors: Qutob Hani , Byrne Micheal 
Published: May 2015

Abstract
The increased demand for more sources of clean energy such as natural gas from unconventional reservoirs has forced the industry to explore the more challenging tight gas reservoirs. Tight gas reservoirs constitute a significant proportion of the world's natural gas resource and offer great potential for future reserve growth and production. However, to meet future global energy demand, access to tight gas reservoirs requires innovative and cost effective technical solutions.
Yet, tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. Exploring and developing tight gas accumulations are both technically and commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery per well. In addition, formation damage is an undesirable operational and economic dilemma that may occur during any phase of gas recovery from tight gas reservoirs. Tight gas reservoirs normally show significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on well productivity in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, damage due to wellbore breakouts, compression damage and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occur through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures.
Prevention, control and remediation of formation damage are among the most important issues to be resolved for efficient exploitation of tight gas reservoirs. Designing certain chemicals and/or treatment procedures for damage control and remediation is not an easy scientific and engineering task. Good understanding of the formation damage mechanisms would allow operators to make informed decision as to the best practices to drill, complete and produce tight gas wells.
In this paper, a review of commonly practiced methods and tools available for prevention, control and remediation of formation damage will be discussed and presented.
Chemical Sand Consolidation as a Failed Gravel Pack Sand-Control Remediation on Handil Field, Indonesia
Authors: Mahardhini Antus , Abidiy Izzad , Poitrenaud Hugues , Wiendyahwati Shinta , Mayasari Fanni , Wood Timothy , Ariadi Dicha , Magee Ceallach 
Published: May 2015

Abstract
Handil field is a mature oilfield located in East Kalimantan Indonesia, operated by TOTAL E&P Indonesie (TEPI). By 2012, there were several wells completed with Gravel Pack completions that were producing sand during production phase. This condition created a hydrocarbon production limitation around 3700 bopd from three oil wells. TEPI were looking at technical solutions to improve well performance. Within the solution options that exist, chemical treatments - that consolidate the near wellbore area - can be a viable alternative for a number of completion types. Chemical sand consolidation can give a formation additional residual strength. This can enhance a maximum sand free rate (MSFR).
One chemical treatment developed is environmentally acceptable by North Sea standards and simple to deploy by in a ‘one pass’ pumping operation. Looking at the completion type and complication during sand control remediation pumping, this chemical was finally chosen. The simpler deployment operation, since there is no overflush, induces less risk during pumping the treatment. The active chemical reacts with connate water in the near well bore area and forms a polymerized network around and between the sand grains. This network imparts additional residual strength allowing the near well bore formation to withstand greater drawdown and fluid flow.
This paper discusses the experiences of TEPI with respect to using the organo-silane based chemical treatment in Handil field, Indonesia. A well intervention campaign treats a number of production zones which were treated separately by sliding sleeve door (SSD) selection. To ensure liquid cleanliness prior injection into formation, the use of coiled tubing was required and the treatment programs were adjusted from standard designs to accommodate this. Most of the operation performed resulted in an increase of the MSFR (leading to production increase). One job result however was not as per expectation. The lessons learnt from these treatments and improvements in candidate selection will be discussed here.
This first coiled tubing application of the organo-silane based chemistry and the need to manage multiple small batches of the water sensitive treatment in a humid and wet environment were challenges to overcome.
A Shallow-Penetration Polymer Sealant for Water and Gas Control: Case Histories and Lessons Learned After More Than 250 Well Interventions
Authors: Vasquez Julio , Curtice Richard 
Published: May 2015

Abstract
This paper presents the field implementation of a shallow-penetration conformance sealant (SPCS) system for water and gas control applications. This system combines an organically crosslinked polymer (OCP) gel system with fluid-loss control additives and noncement particulates. The additives/particulates provide leakoff control properties, which can lead to shallow matrix penetration of the sealant. This filtrate from the leakoff is then thermally activated at a predicted time. After exposure to the bottomhole temperature of the well, it forms a three-dimensional (3D) gel structure that effectively seals off the targeted interval. This system can be considered an alternative to conventional cement squeeze operations in scenarios where these types of treatments are not an option. The system can either be bullheaded into the wellbore or deployed with coiled tubing (CT). The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion. Selective reperforation of treated zones is an option if the zone still has hydrocarbon potential. The system can be easily washed out of the wellbore compared to cement, which must be drilled out. Case histories are presented along with lessons learned from more than 250 treatments highlighting the diagnostic stage.
The SPCS system has been successfully tested to withstand a differential pressure of at least 2,600 psi and is resistant to acid, CO2, and H2S environments. (1) SPCS performance testing, (2) recent improvements to the system, (3) design considerations and best practices for field implementation, and (4) case histories are discussed. The working temperature range of this system is 40 to 400°F. To date, more than 250 treatments have been performed with the SPCS system globally to address conformance problems, such as perforation shutoff, gravel-pack isolation, fracture shutoff, poor zonal isolation, and/or casing-leak repair. Because of the capability of the SPCS system to withstand pressure, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others. A primary objective of this paper is to help provide assistance during the candidate selection process and design of this particular sealant treatment.
Mitigating Formation Damage by Using Completion with Built-in-Casing Perforations Instead of Perforation with Explosive Charges
Authors: Rastegar Reza , Munawar Mohammed , Nowowiejski David , Granberg Ståle , Mehus Cathrine , Benson Andy 
Published: May 2015

Abstract
The downside of the conventional perforating method with explosive charges and guns is that it is risky. In addition to this, the method has a negative effect on the near wellbore permeability, and it creates mechanical damage. The impact stress associated with shaped charge and the outward travelling shock wave weakens the rock matrix, which increases the risk of sand production. Another negative impact of the shape charge is the creation of a low permeability zone, in which sand grains are forced toward the vicinity of the perforation chamber. For example, a perforation process with a 55% permeability reduction around the perforation tunnel led to 60% reduction in well productivity. An intended large underbalance differential pressure offers, to some extent, a solution to clean up the crushed zone. However, the de-bonded and weakened structure of the damaged zone is irreversible. The required surge pressure to clean up the perforations varies from 200 to 5,000 psi, because not all the perforations react the same way.
On the other hand, built-in nozzles cause no damage to the formation, because no charge or shock is imposed to the formation. Furthermore, there is no longer an impact from underbalance or overbalance pressure differential between wellbore and formation. In this paper, we will introduce the engineering and mechanism of built-in casing (BIC) nozzles. With BIC, nozzles are activated from surface with deployment of specific activation tools. Once the tool engages with the targeted profile, the nozzles are opened and projected to the wellbore fluid. With circulation of cement-dissolving fluid, cement breaks and formation connection is initiated. Quantity and size of nozzles are engineered as per downhole production design criteria.
In unconsolidated or poorly consolidated reservoirs, the strength of the rock structure should be evaluated to reduce the risk of sand production. Ultimately, the differential pressure shall be high enough to effectively clean the perforations, but not so high as to cause sand production.
As mentioned above, there are a great deal of scenarios and variable parameters involved in perforation with shape charges that have to be taken into consideration to ensure an effectively performing set of perforations. Because such a study and remedial approaches are costly and not always guarantee results, an alternative method is to use BIC perforations.
Stabilizing CO2-Foam using Nanoparticles
Authors: Emrani Arezoo S. , Nasr-El-Din Hisham A. 
Published: May 2015

Abstract
Foamed fluids have been used for decades to diminish formation damage in nearly all kinds of unconventional reservoirs with a wide range of pressures. Although water-based fluids are widely used in the oil industry as one of the most economic hydraulic fracturing methods, foams are another substitute to fracture water-sensitive reservoirs at which damage to pore throats is caused by swelling clays or fines migration. The mixture of CO2 and surfactant as a CO2-foam not only reduces formation damage by minimizing the quantity of aqueous fluid which enters the formation, but significantly improves sweep efficiency. Even though it is common to utilize surfactants in order to generate and stabilize foams, surfactants tend to degrade at high temperatures and in high salinity environments. Adding nanoparticles can solve the aforesaid problems and can increase foam stability.
The choice of surfactant concentration is a critical step in preparing more stable foams. In the present work, using CO2/alpha olefin sulfonate (AOS) solution as a new foaming solution is introduced for optimizing surfactant concentration in order to generate a stable CO2-foam in unconventional reservoirs. Several experimental studies were conducted to obtain the optimal surfactant concentration using a pendant drop method for CO2/solution and CO2/nano solution. Moreover, the effects of temperature, pressure, salinity, and surfactant concentration on surface tension and the critical micelle concentration (CMC) value were studied at high pressure and high temperature (HP/HT). In these experiments the temperature ranged from ambient conditions to 302°F, while the pressure increased from atmospheric up to 435 psi. AOS solutions were prepared using different brine concentrations ranging from 1 to 10 wt% of NaCl and different surfactant concentrations from 0 to 1 wt%.
Experimental results indicated that the CMC value increases as temperature increased. It also decreased while salt concentration increased. Furthermore, for a given temperature and salinity, the results did not exhibit changes in the CMC value when the pressure increased. The addition of nanoparticles decreases the CMC value.
A number of research studies have been conducted to investigate the CMC value and surface tension for AOS at ambient conditions using N2. However, minimal work has been performed in order to determine such characteristics at reservoir conditions. The present work will provide a new foaming solution in order to evaluate and optimize surfactant concentrations. The present work will also investigate the effect of mixtures of surfactant and nanoparticles on the formation of stable CO2-foam in unconventional reservoirs.
GLDA/HF Facilitates High Temperature Acidizing and Coiled Tubing Corrosion Inhibition
Authors: Reyes Enrique A. , Smith Alyssa L. , Beuterbaugh Aaron , Calabrese Tristen 
Published: May 2015

Abstract
An existing limitation of chelant-based fluids available for sandstone acidizing with hydrofluoric acid (HF) is the presence of sodium in the concentrate of the aminopolycarboxylate fluid, which is common in all chelating agents soluble below pH 3.5. The presence of sodium complicates stabilization of the fluid during acidizing processes because of the myriad of chemical reactions that can impact the outcome of a treatment. The use of chelating agents has expanded the temperature range as well as the type of clay minerals that can be exposed to an HF fluid; however, limitations still exist. Core flow testing at 360°F and corrosion testing from 265 to 360°F were conducted. Flow tests were performed using outcrops of two types of sandstones and inductively coupled plasma (ICP) analysis was conducted to elucidate the ionic composition of the spent fluid. Results reported stem from core flow testing with glutamic acid diacetic acid (GLDA) containing HF at very high temperatures (360°F). To encompass a broad range of mineral composition, two types of sandstone cores were employed—heterogeneous (Bandera, 65% quartz) and clean (Leopard, 95% quartz). Corrosion inhibition of the GLDA/HF fluid for use with coiled tubing (CT) was achieved up to 320°F, employing varying classes of inhibitors. The GLDA/HF fluid exhibited lessened corrosion tendencies and could be inhibited for at least 6 hours at 360°F for drillpipe (mass loss rates of 0.025 to 0.05 in./ft2 were obtained).
The presence of sodium in GLDA/HF could be managed, leading to effective permeability improvement of the Bandera core, while the Leopard core underwent a decrease in overall permeability; this latter observation was attributed to the formation of metal fluorides. Neither the presence of CaCO3 in the Bandera substrate or the use of KCl brine substituting for the usual NH4Cl led to permeability impairment. The overall results indicated that 1% HF and 0.6 M GLDA with an auxiliary agent could circumvent the expected problems associated with HF acidizing and modification, volume minimization, or elimination of preflushes. The use of the GLDA chelant facilitates, when using CT to deliver fluid to hot zones (which can be susceptible to formation damage if aggressive fluids based on HCl or formic acid are used, or if acetic acid is employed), could be jeopardized because of the difficulties inhibiting the corrosive effects of HF, HCl, formic, or acetic blends.
Making Clays Water Resistant: New Technology That Minimizes Formation Damage
Authors: Monroe Terry , Bhaduri Sumit , Koch Amber , Lant Kimberly 
Published: May 2015

Abstract
Formation damage and the resultant reduction in hydrocarbon production rates due to clay expansion are long-recognized problems (Ohen, 1991). The clay damage may occur during the drilling, completion and production phases of well operations. Often the remediation of clay damage is inadequate, providing only temporary improvements in hydrocarbon production. The prevention of clay expansion presents a challenge; fit-for-purpose chemistries exist, and are a function of clay identity and operational phase of the well.
Two broad subsets of clay damage mechanisms are chemical and mechanical considerations (Bennion, 2002). The focus of this study is to evaluate the minimization of clay hydration by coating clays to prevent chemical or reactive damage. An example of chemically induced formation damage would be clay swelling. On exposure to introduced aqueous fluids, other than interstitial water, sensitive clays will hydrate detrimentally. The end result can be subsequent hydrocarbon flow restrictions due to a decrease in pore space and detrimental formation softening allowing embedment of proppant. Chemical methods of ameliorating clay expandability potential fall into two broad categories: temporary and permanent stabilizers. The temporary clay control additives prevent clay swelling by increasing the ionic strength of treatment fluids, e.g., potassium chloride. Permanent clay stabilizers create a protective sheath around the clay.
The formation of a self-assembled monolayer (SAM), where the chemical covalently bonds to the siliceous formation surface, offers a more robust chemical coating on the clay surface. This coating acts as a chemical shield, which prevents subsequent wellbore fluids from interacting with the formation surface.
A new chemical treatment has been evaluated and, as discussed in this paper, the laboratory test results indicate the application of a hydrophobic coating offers substantial clay protection in water sensitive environments.