bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sand Consolidation Testing in an API RP 19B Section IV Perforation Flow Laboratory
Authors: Haggerty D. J. , Manning J. D. , Nguyen P. D. , Rickman R. D. , Dusterhoft R. G. 
Published: May 2009

Abstract
Formation consolidation is a form of sand control that was used extensively in the past, but has been largely replaced by mechanical systems, such as gravel packs or expandable screens. This change has arisen because of a level of uncertainty regarding effective chemical placement and reliability. Challenging economics in the petroleum industry began to make alternative completion techniques more attractive for remediation applications, for developing and producing by-passed reserves behind blank pipe, and for completing marginal reservoirs. Low-cost completion alternatives are actively being sought for both injectors and producers.
To understand the performance of various consolidation options, a series of tests was performed on samples of Castlegate sandstone, incorporating actual perforating operations in the lab to evaluate both treatment placement and performance under reservoir conditions. This paper provides details about the testing process that was used, as well as comparative results for various consolidation technologies, including curable and non-curable agents resulting in various degrees of cohesion between formation particulates. Post treatment evaluations included flow testing single and dual phase fluids under in-situ conditions, as well as post mortem evaluations of chemical placement and mechanical properties.
Section IV perforation flow testing provided a realistic modeling technique to understand the effectiveness of a consolidating agent with respect to its placement or coating behavior, which in turn directly affects the resulting strength and retained permeability after chemical treatment. Results from the flow testing indicate that a critical strength is required to lock the treated sand in place and to overcome the drag force generated by flow. Depth of treatment penetration into the formation matrix is a function of treatment volume, pressure drop, and permeability. The amount of consolidating agent coating on the sand and the resulting strength depend on the concentration of the agent in the treatment solution. With efficient strength as a result of the consolidating agent treatment, only a small quantity of sand was observed to produce from the treated perforation, either with single or dual phase fluids, when compared to a much larger amount of sand produced from the perforation that lacked treatment, even when the perforation was subjected to a lower flow rate.
Modeling the Effect of Asphaltene on the Development of the Marrat Field
Authors: Yi T. , Fadili A. , Ibrahim M. , Al-Matar B. S. 
Published: May 2009

Abstract
This paper describes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional simulation model with asphaltene modeling facilities. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment, and the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability. A workflow was established in the study to i) characterize the equation of state (EOS) by analyzing the fluid PVT and asphaltene data from the lab; ii) calibrate the asphaltene model input parameters using the core flood experimental data; and iii) incorporate the EOS and the asphaltene parameters into the full field simulation model.
The model was used to analyze the effects of asphaltene on various development scenarios, including depletion and water injection. For each scenario, the following were calculated and analyzed: field performance including production of oil, gas, and water; asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment; formation damage and the effect of rock wettablity changes.
The results show that the formation could be severely damaged near the producers where asphaltene is more likely to precipitate because of lower pressures (below the asphaltene onset pressure) and longer time exposure to a larger amount of oil. Formation damage could be reduced by flushing away the deposited asphaltene using higher flow rates if plugging is not significant. The water injection scenario with higher injection rate and higher production rate with BHP limit above 6,000 psia results in less asphaltene adsorption, more entrainment, and therefore less deposition. This in turn causes less permeability damage and more oil production.
The Challenge of Modelling and Deploying Divertion for Subsea Scale Squeeze Application
Authors: Jordan M. M. , Mackay E. J. 
Published: May 2009

Abstract
Due to the increased cost of scale management in subsea compared to platform or onshore fields, and because of the more limited opportunities for interventions, it is becoming increasingly important to carry out a risk analysis process for scale management as early as possible in the field development plan. A critical part of this process is to evaluate methods of chemical deployment for reservoirs where near wellbore scale has been identified as a significant risk to production – often leading to consideration of the scale squeeze process.
This paper discusses how scale squeeze treatment deployment options can be modelled and demonstrates the comparison of mechanical and chemical diversion (particulate or viscosified fluids) with simple rate diversion. In subsea heterogeneous wells diversion via bullhead deployable treatments can be more cost effective than deployment via a rig and coil tubing, provided the treatment distribution is as effective. The ability to model the application process is critical in the economic assessment of coil/rig vs. fix facility deployment in deepwater fields.
The paper will outline the process of chemical selection, reservoir/near wellbore modeling and field application for solid, viscosified divertors or deployment options where high pump rates are utilized to achieved better chemical placement.
Field treatments where this process has been utilized (North Sea, Brazil and West Africa) will be presented along with the results of these treatments. Practical issues related to overcoming the challenges of subsea flow line cleaning and the effective rates required to achieve diversion are discussed, as are monitoring methods following such treatments to ensure effective placement has been achieved.
Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Fluid System, Executed from a Supply Vessel; Black Sea Offshore
Authors: Bukovac Tomislav , Belhaouas Rafik , Perez Daniel , Dragomir Alexandru , Krilov Zoran 
Published: May 2009

Abstract
Current offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies.
To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single pumping operation, improving efficiency and adding additional savings to the process.
Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks.
To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously.
This novel multistage fracturing system combined with polymer-free viscoelastic surfactant fluid system prepared with seawater was applied in the World for the first time. Results indicate a sustained increased production.
Optimization of Selective Stimulation Treatments Using Coiled Tubing and Fluidic Oscillator Yields Additional Oil Production from Carbonate Formations in Southern Mexico: Case Studies
Authors: De la Fuente Rodríguez Juan Jose , García Torres Francisco , Gutierrez Joel Vladimir Ulloa , Duverney Eduardo Soriano , Campos Carlos Caballero 
Published: May 2009

Abstract
This paper documents efforts to seek alternative and effective treatments for stimulating wells in southern Mexico. It was desired to make treatments more selective, stimulating only areas of oil without contacting contributing areas of water or gas. Stimulation treatments were performed using coiled tubing (CT) and a fluidic oscillator to generate waves of fluid.
In the southern region of Mexico, the commercial production of hydrocarbons is in reservoirs that are naturally fractured carbonates with permeability of 25–150 mD, porosities of 5–15%, and are depleted as a result of exploitation. Also, the progress of oil-water contact and gas-oil contact present challenges when designing treatments for stimulation.
The damage mechanisms encountered in these wells included blockage by water, paraffin, asphaltenes, and scale depositions, which were generated in the near-wellbore area of the well.
To enhance the effect of the stimulation systems, the fluidic oscillator was used to generate a frequency of impact of 300 to 600 Hz on the formation, weakening the damage and efficiently removing it.
Commonly, in the southern region of Mexico, 90% of the stimulation treatments are bullheaded; however, in highly deviated wells with two or more pay zones, the use of CT with the fluidic oscillator offers an alternative to increase the effectiveness of acid placement.
The synergy of CT, the generation of fluid waves, and the selection system for optimal acid flow through each hole have led to significant results of reduced cost, time, and, in turn, optimizing the volumes of systems required to stimulate wells.
In this paper, results achieved by carrying out selective stimulation treatments as well as technical and economic benefits of using CT and the generation of fluid waves as an alternative stimulation treatment for oil wells are presented.
The Effect of Gas on the Injectivity of Particles in Sandstone
Authors: Nguyen Q. P. , Currie Peter K. , Bouzanga P. S. R. 
Published: May 2009

Abstract
Many operations involve the injection of fluids into the formation around a well. In many cases, the fluids contain colloidal particles, either initially present or introduced during the operation through dirt or naturally-occurring particles. Therefore, all injection schemes potentially suffer from injectivity decline. This injectivity decline is caused by clogging of the formation by particles, forming an external filter cake on the surface of the formation and blocking the pores inside the formation.
This paper reports on the effects of gas on the injectivity of particles in sandstone. Experiments were performed in which water containing micron-sized particles (hematite) was injected into sandstone cores with or without small gas bubbles (nitrogen) present in the water. The position and amount of particle deposition could be determined both visually and by chemical analysis. It was found that the presence of gas reduces the external filter cake formed on the inlet surface of the core. Also, with gas, the particles penetrate deeper inside the core, and more particles pass right through the core and are detected in the effluent stream.
The same effects are enhanced when the mixture of gas bubbles and water is replaced by a foam. This suggests that the presence of gas/water interfaces has a major influence on the retention of particles in the sandstone. Possible mechanisms are discussed.
The pressure drop across the core, when gas or foam is present, is initially higher than in an identical test without gas, because of relative permeability effects or foam flow resistance. But since fewer particles are retained, ultimately the pressure drop is significantly less when gas is present. This effect may be significant in injection operations involving foam and offers ways to mitigate injectivity loss.
Observations on Gas Permeability Measurements under HPHT Conditions in Core Materials Exposed to Cesium Formate Brine
Authors: Downs J. D. 
Published: May 2009

Abstract
Natural gas in its native environment is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions. Full water saturation of gases used in laboratory core flooding tests may not always be achieved, and it is known that the use of dry gas in such experiments can artificially reduce core permeability to gas by dehydrating and crystallising any brine residues left within the cores. This problem of permeability impairment, as a result of water vaporisation by gas, might be expected to become more acute or evident in laboratory tests with high-pressure high-temperature (HPHT) reservoir cores containing high salinity formation brine and high-density completion brine filtrates. These brines may contain salt concentrations that are already close to saturation levels and are more susceptible to crystallisation by dehydration.
The objective of the work described in this paper was to look at the effect of gas humidification levels on the gas permeability of North Sea HPHT reservoir core material exposed to high-density cesium formate brine under HPHT conditions in laboratory core flooding experiments. The results from core flooding experiments at 200°C (392°F) indicated that full HPHT-humidification of the gas phase resulted in a higher gas return permeability when compared with a test using gas humidified at room temperature and high pressure. This finding highlights the importance of ensuring that any gases used in HPHT core flooding tests are fully saturated with water vapour at the test temperature and pressure. It seems likely that the impact of gas humidification levels will be amplified in very low permeability cores subjected to high drawdown pressures.
Wormhole Formation in Carbonates Under Varying Temperature Conditions
Authors: Kalia Nitika , Glasbergen Gerard 
Published: May 2009

Abstract
Matrix stimulation of carbonates involves injecting acid into the wellbore where it reacts with the formation and bypasses the damage. Different types of patterns, like face dissolution, wormhole, and uniform dissolution, are created as a result of the dissolution process. During acid injection, the fluid temperature is typically lower than the formation temperature. As a result, thermal interactions between the fluid and formation occur and lead to retardation of surface reaction rate, decrease in fluid viscosity, and density and increase in diffusivity. Experimental studies of the effect of temperature on wormholing conducted in the past indicated that, depending on the type of acid being injected, a high formation temperature can either aid or impede stimulation. This implies that either a higher or lower total volume of acid might be required to increase the medium permeability. In addition to the temperature difference between the fluid and formation, the fluid-injection rate is also often varied during a single acid job. Therefore, the type of patterns created under lab conditions might not be representative of those formed in the field. Hence, it is not straightforward to design a treatment based on experimental data when flow rate and temperature variations are involved.
In this work, a two-scale continuum model is developed to understand the coupling between flow, reaction, and transport under transient temperature and flow-rate conditions. The effect of fluid temperature on wormholing has been investigated. Specifically, it is shown that injecting a colder fluid in a high-temperature formation leads to a higher wormhole density under laboratory conditions. In addition, it is shown that the acid volume required to achieve a given increase in permeability also depends on the temperature of the injected fluid.
It is important to investigate techniques that enhance hydrocarbon recovery from carbonate reservoirs as more than 50% of the world's current hydrocarbon reserves are present in these formations. The modeling study in this work attempts to answer critical questions pertaining to the effect of temperature variations on stimulation design. In particular, the results from this work can be used to optimize acid volume, flow rates, and acid types in a matrix-acid design.
In Situ Water Blocking Measurements and Interpretation Related to Fracturing Operations in Tight Gas Reservoirs
Authors: Bazin B. , Peysson Y. , Lamy F. , Martin F. , Aubry E. , Chapuis C. 
Published: May 2009

Abstract
Invasion of aqueous drilling, completion or fracturing fluids can reduce the relative permeability to gas and thereby causes a waterblock. In the case of low permeability formations, the capillary pressure tends to be high because of the small pore size. Clean up of water blocks requires high draw down unless water vaporization by the flowing gas is improved by using specific additives like alcohols.
The purpose of this work is to investigate fracture face damage by measuring relevant petrophysical parameters: absolute permeability damage and gas return permeabilities. Measurements are performed in representative conditions of a fracturing operation in a tight gas formation: cores with an absolute permeability of 10 microDarcy set at Swi, experimental pressure of 200 bars for the fracturing fluid invasion. Water and gas saturations during the invasion of the fracturing fluid as well as during the gas back flow are monitored thanks to a XRay equipment. Adding alcohol in the fracturing fluid has a striking effect on resolving the water block. Cake formation on the simulated fracture face is also discussed.
Numerical simulations are performed to assess relative permeabilities from the experimental results. It is shown that the hysteresis of gas and water relative permeabilities has a strong impact on the rate of water removal. Sufficiently high pressure draw down is crucial to overcome capillary forces and initiate alcohol assisted vaporization process. Water removal by water vaporization is assessed and compared to the experimental results.
Case Study:YM204 Obtained High Petroleum Production by Acid Fracture Treatment Combining Fluid Diversion and Fracture Reorientation
Authors: Zhou Fujian , Liu Yuzhang , Liu Xiongfei , Xiong Chunming , Yang Xianyou , Jia Xinfeng , Li Xiangdong , Wang Daobin , Zhang Fuxiang , Shi Hongxiang , Lian Yifeng , Tao Shijun , Qian Chunjiang 
Published: May 2009

Abstract
TARIM is the largest basin abundant in carbonate reservoirs in China. Acid fracturing is the main technology for exploration and development in TARIM carbonate reservoirs, which featured with great depth (4500–7200m), high temperature (250–320F Degrees) and extreme heterogeneity due to fracture formation. If the azimuths of natural fractures and in-situ stress match the azimuth of fracture-and-cavern area from the well, the acid fracturing treatment would generate good effect in general; otherwise, the effect will be non-ideal.
A novel diversion acid fracturing (acidizing) technology, which combines fracture reorientation technology and fluid diversion technology, has been developed to solve the problem. When hydraulic fractures are initiated and extended in unfavorable direction, the fracture reorientation technology utilizing DCF (Degradable Cleaning Fluid, with great block efficiency and high compressive strength) can be adopted to temporarily block the fracture and ensure the hydraulic fracture would reorientate in advantageous direction. DCF is a mixture of TDF (temperature-degradable fibers), which would remain stable at 260 Degrees Fahrenheit while degrade thoroughly at 280 Degrees F, and soluble particles. By using visco-elastic surfactant based self-diversion acid, the fluid diversion technology could achieve deep penetration and efficient acid placement.
Well YM204 has no production before stimulation. The azimuth of maximum principal stress is about NE45 Degrees. FMI data shows that natural fractures in Ordovician carbonate formation are oriented at NW315-SE135 Degrees while there is a fracture-and-cavern area about 150m to the northeast of the wellbore according to the seismic lateral prediction. Thus, acid fracturing treatment combining fracture reorientation technology and fluid diversion technology was conducted in this well. Post-treatment evaluation indicates that the fracture-and-cavern area has been connected to the wellbore and the output remained over 100t/d of oil and 7000m3/d of gas.
Determination of Skin Radius Caused by Drilling Operations in Naturally Fractured Reservoirs
Authors: Zamiri Mehdi , Shadizadeh S. R. 
Published: May 2009

Abstract
Drilling fractured formations by overbalanced method causes lost circulation of drilling fluid in fractures. The lost circulation in drilling fractured zones has been traditionally accepted due to inability to control its occurrence. Most of drilled wells in fractured oil zones after completion are conducted on acid job in order to obtain well flowing. If the radius of skin due to lost circulation of drilling fluid through fractured oil zones be determined, the volume of acid needed to conduct any acid job can be calculated. The main goal of this work is to obtain a mathematical model for determination of skin radius in naturally fractured oil reservoir wells.
In this study, one vertical fracture is assumed to symmetrically intersect a wellbore. During a lost circulation drilling fluid enters the fracture and displaces formation fluid. The mechanism of lost circulation through the modeled porous medium is formulated using mass transfer phenomena. Obtained equations give concentration of the lost fluid with respect to time and position. Filtration of the drilling fluid at walls of the fracture is considered to be exponential which is ceased after mud cake is formed. A simulator is developed using derived equations in this work. The concentration of the drilling fluid could now be plotted against the position in the fracture and also against the position in lateral direction for each point in the fracture at a given time. These curves tend to be S-shaped.
The position in the fracture at which the curve of concentration reaches zero could be considered to represent skin radius caused by drilling operation. Similarly the position in lateral direction at which the concentration reaches zero represents lateral penetration of the drilling fluid in the matrix from its corresponding position in the fracture.