bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiple Transverse Fracturing in Horizontal Open Hole Allows Development of a Low-Permeability Reservoir in the Foukanda Field, Offshore Congo
Authors: Casero Alberto , Tealdi Loris , Ceccarelli Roberto Luis , Ciuca Antonio , Pace Giamberardino , Malone Brad , Athans James 
Published: January 2009

Abstract
During the past decade, multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it is becoming the standard completion practice in many areas.
The reasons for the success of this technique vary, but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing treatments in a single pumping operation.
Nevertheless, the high direct and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology to offshore applications. Sometimes, the misplaced perception of hydraulic fracturing as risky and costly operation prevented, rather than encouraged, its application in marginal offshore oilfields. Recent increases in oil prices and the success in onshore applications have encouraged the use of hydraulic fracturing in offshore applications.
This study documents the successful effort of taking these techniques to the offshore environment. Transverse fracturing with multistage completion concept— with properly engineered design of well trajectory—can make the difference between the economic success or failure in the field development of low-permeability reservoirs. This study used multidisciplinary and integrated approach to design and execute the treatments, involving reservoir, production optimization, and fracturing engineers from the early stages of well planning to construction.
The multilayer Foukanda field, located 52km offshore from Pointe Noire, Congo, has a low permeability and virgin target that was considered noncommercial after discouraging results of two wells. Based on the production results of three cased-hole wells in an analogous field where multiple propped fracturing was applied, the operator decided to drill an open-hole horizontal well that was to be multi-fractured. The initial 90 days average production of this Foukanda well was more than 2500bbl/day. This production rate was double the simulated rate of a vertical well and opened a wide range of further developments both in Foukanda and in other analogue fields in the offshore Congo.
A Simple and Accurate Model for Well Productivity for Hydraulically Fractured Wells
Authors: Friehauf Kyle E. , Suri Ajay , Sharma Mukul M. 
Published: January 2009

Abstract
A new model is developed that calculates the productivity of a hydraulically fractured well, including the effect of damage of the fracture face from fluid leak-off. Results of the new model are compared with three previous models (McGuire, Prats and Raymond). The existing models assume either elliptical or radial flow around the well with permeability varying azimuthally. Significant differences in the calculated well productivity indicate that earlier assumptions made about the flow geometry can lead to significant overestimates of well PI. Agreement with Prats analytical solution is achieved for finite conductivity fractures and no fracture damage. It is shown that the use of either McGuire and Sikora's or Raymond's model to estimate improvement in well PI in fractured wells can lead to a significant over-estimation of the well PI. The new model provides a useful tool to quickly calculate the productivity of wells that have both a finite-conductivity fracture and damage in the invaded zone. The simple and discrete nature of the model makes it ideal for implementation in spreadsheets and to connect to fracture performance models.
Clean-up of the damage in the invaded zone depends on the capillary properties of the formation and the drawdown pressure applied across the damaged zone during production. If capillary forces are small, and drawdown pressure is high, the water will be recovered, resulting in negligible damage. It is found that the invaded zone will cause significant damage when the permeability of the damaged zone is reduced by over 90%. For low permeability, depleted formations, where water recovery is poor, the fracturing fluid should be energized with a gas component so that the relative permeability damage to gas inflow can be minimized.
Application of a New Compositional Model for Hydraulic Fracturing With Energized Fluids: A South Texas Case Study
Authors: Friehauf Kyle E. , Sharma Mukul M. , Sullivan Richard B. 
Published: January 2009

Abstract
A gas component (CO2) is added to fracturing fluids in tight gas wells of South Texas in order to energize, or stimulate the invaded zone for improved flowback. It was observed that traditional fracturing fluids were being trapped because of the lack of drawdown pressure caused by depletion of the reservoir. This study uses a recently developed energized fracture model to predict fracture behavior. It is shown that this model can be used instead of costly trial and error methods in the field to help improve upon the design of the treatments. This study investigates the effects of drawdown pressure, inlet gas composition (or quality), inlet temperature, flowrate, base viscosity, and reservoir pressure on three previous fracture designs. The effect of energizing only specific stages of the fracture treatment is also demonstrated.
Our results show that if the drawdown pressure is much larger than the capillary forces holding water in the invaded zone, energizing the fluid may not be necessary. In wells with low drawdown pressure, adding CO2 to energize the fracturing fluid may be able to completely remove damage by increasing the gas saturation in the invaded zone. Specifically for the wells that were modeled, we determined that 30 quality CO2 would be sufficient to stimulate the invaded zone. When the reservoir pressure was as low as 800 psi, even less CO2 was necessary because of additional expansion of the gas during production. Pumping of a gas with high quality (&gt; 52%) will result in foaming of the fluid that will increase the fracture fluid viscosity. This may be undesirable in tight formations where fracture length is favored over conductivity. Pumping volumes should be corrected in order to account for the expansion of gas when there is a large difference between inlet and reservoir temperature. Changing the inlet temperature of the fluid does not greatly affect the performance of the fractured wells in this area. No compositional or phase behavior issues arose when altering the flowrate or the base fluid viscosity. Finally, it is recommended that every stage of the treatment be energized. However, in some instances it may be possible to stimulate the invaded zone by energizing only certain stages of the treatment.
Hydraulic Fracture Offsetting in Naturally Fractures Reservoirs: Quantifying a Long-Recognized Process
Authors: Jeffrey R. G. , Zhang X. , Thiercelin M. 
Published: January 2009

Abstract
Offsets along the hydraulic fracture path have been observed in mapping of mined fractures and attempts have been made to reproduce their effects on fracture growth using numerical hydraulic fracture models. Such offsets have long been recognized as sites of restricted width in the fracture channel, potentially leading both to significant pressure drops and to proppant bridging as fluid and slurry move through the restrictions. New modeling results are presented that quantify these and other effects of offsets by using a coupled 2D hydraulic fracture model. Offsets are geometrically characterized by their angle with respect to the main fracture direction and by their length. Quantitative comparisons on fracture length, width and injection pressure are made for several offset angles and lengths. Large increases in net pressure and associated increases in overall fracture volume are shown, which can result in increased treatment costs, slower fracture growth, and shorter overall fracture length development compared with a straight fracture.
Analysis of Reserve Recovery Potential from Hydraulic Fracture Reorientation in Tight Gas Lenticular Reservoirs
Authors: Benedict D. S. , Miskimins J. L. 
Published: January 2009

Abstract
The basic concept of hydraulic fracture reorientation involves inducing a second artificial fracture into the producing zone, with this secondary fracture propagating in a different direction from the original. For reorientation to occur, the near wellbore stress has to have altered in orientation from the time the original fracture was created. To investigate the effects of this action on reserve recoveries in tight gas lenticular reservoirs, a series of simulations were run in a reservoir modeling program where orientation was assumed to occur at various given angles. The reservoir and fracture properties that were manipulated in order to run the model under different scenarios included the following: fracture orientation, fracture half-length, fracture conductivity, reservoir area, permeability anisotropy, and geologic aspect ratios. For each scenario, production of the field was then simulated over a period of time to study sensitivities of the parameters.
The research presented in this paper led to the following main conclusions: 1) refracture reorientation can be effectively studied using a reservoir simulator through manipulation of the fracture and reservoir parameters over time; 2) incremental gains in production and pressure responses were observed with the variance of these various reservoir and fracture properties that were consistent with the possibility of hydraulic fracture reorientation; and 3) results indicate that even assuming refracture reorientation is possible, it would not be economical under typical conditions in most tight gas lenticular reservoirs due to their limited volumes.
Hydraulic Fracturing Using Heavy Brine and Microseismic Monitoring in Yufutsu Oil and Gas Field
Authors: Kamitsuji R. , Nagai K. , Matsuno Y. , Ohsaki Y. , Tamagawa T. , Tezuka K. 
Published: January 2009

Abstract
Hydraulic fracturing using heavy brine was conducted to stimulate the deeper part of the completion interval in the naturally fractured reservoir, Yufutsu Japan. The microseismic monitoring and the temperature surveys showed that the deeper part was stimulated effectively as expected.
The Yufutsu oil and gas reservoir is seated at around 4 km depth in the Southern Ishikari Plain, central Hokkaido, in northern Japan is known as a basement fractured reservoir. The water frac inducing shear dilation is one of the effective stimulation methods for the fractured reservoir. However it is difficult to stimulate the bottom part of the vertically long completion interval with seawater or slick water because the gradient of the fracture closure stress (that is typically 0.6-0.7 psi/ft, equivalent mud weight 1.4-1.6 sg) is commonly larger than that of the injection fluid. The heavy brine (CaCl2/CaBr2 brine 1.8 sg) realizes a pressure gradient larger than the fracture closure stress gradient that can stimulate deeper zone effectively. The numerical prediction using "SHIFT" simulator shows consistent results with the above-mentioned considerations. SHIFT simulates shearing of fractures and related permeability changes in a dynamic process by coupling analyses of the fluid flow and the shear dilation along fractures.
The target well has a long completed interval of 700 m. The deeper part of this well showed poor productivity due to a damage of lost circulation materials. The fracturing operation using the 1.8 sg CaCl2/CaBr2 brine was conducted with the objective to stimulate the damaged zones. About 200kL of heavy brine was injected. The microseismic array sensor was installed in the adjacent well to monitor the stimulation during the injection.
Approximately a thousand microseismic events were observed during the injection. The location of the microseismic events showed that the deeper part was stimulated effectively. A temperature survey conducted after the stimulation revealed the new production zones appeared on the temperature profiles as anomalies which had not been seen before. The AOFC of the well increased by a factor of 1.5.
Assigning value to stimulation in the Barnett Shale: a simultaneous analysis of 7000 plus production hystories and well completion records
Authors: Valkó Peter P. 
Published: January 2009

Abstract
Analysis of publicly available monthly production history and well completion records can shed light onto such long-standing questions as 1) what is the value of a stimulation (re-stimulation) treatment in the Barnett Shale, 2) how does the ultimate recovery depend on treatment type and size, 3) what factors determine the performance of a fractured well. This study starts with the month-by-moth analysis of production history for all gas wells in the Barnett Shale. Using a specialized decline-curve analysis methodology developed for shale gas wells, significant production behavior changes are automatically detected and jumps in estimated ultimate recoveries are calculated for individual wells as well, as for groups of wells. The study then continues with the textual analysis of publicly available well completion records consisting of more than 16 Gigabyte data. The obtained database is submitted to analysis relating ultimate recovery to well inclination, to location, to treatment parameters, etc.
Comprehensive Coupled Modeling Analysis of Stimulations and Post-Frac Productivity—Case Study of a Tight Gas Field in Wyoming
Authors: Settari A. (Tony) , Sullivan R. B. , Rother R. J. , Skinner T. K. 
Published: January 2009

Abstract
This paper presents a new methodology of coupled hydraulic fracturing, geomechanical and reservoir modeling, and an example of integrated analysis of a tight gas well. The new modeling technology and its advantages in field application are demonstrated on a case study of a &quot;science well?? in a tight gas Wyoming field. A detailed model of the well included its entire fracturing and production history, and was constrained by a large amount of field measurements. The model was successfully history matched to all of this data using a common reservoir description. This novel approach thus results in much higher level of confidence compared to using uncoupled models with different assumptions.
The history matching process provided insight in the mechanics of fracturing and flow in this field, and the importance of geomechanical effects. Some of the most important findings are that the formation permeability is highly stress sensitive and increases dramatically during frac injection, fracture length and conductivity is highly variable during flowbacks, and geomechanical effects on conductivity are still evident after several months of production. The calibrated model was then used to assess the gains in productivity possible from improved technology of fracturing, resulting in larger conductivity and length of fractures.
Frac Fluid Recycling and Water Conservation: A Case History
Authors: Gupta D. V. S. , Hlidek B. T. 
Published: January 2009

Abstract
Shallow gas fracturing is very prevalent in Western Canada. Several thousand wells are typically drilled and completed in the shallow gas fields every year. All these wells are typically hydraulically fractured. Prior to 1999, after testing for micro-toxicity, the flowback fluid was allowed to be land farmed in Southeastern Alberta. In that year, the Alberta Energy and Utilities Board began more stringent enforcement of Guide 58, which required that flowback fluid be disposed in a disposal well. More recently, several years of drought conditions in the shallow gas areas of Southeastern Alberta have caused water shortages.
Prior to 1999, the flowback from a particular surfactant-based fracturing fluid could be successfully land farmed. One operator typically had a project of 300 to 400 wells with an average of 5 fracs per day during spring/summer. When the fluid could no longer be land farmed, attempts were made to recycle the flowback fluid. The chemistry of the surfactant gel fluid was insensitive to the water quality, which made the recycling concept successful. Several cost advantages were achieved, which will be detailed in the paper. These included fresh water costs, disposal costs and chemical costs. An additional advantage that was realized involved a 50% reduction in the fresh water requirements for a project.
The paper will detail the chemistry of the fracturing gel, its field application, the optimized recycling operation and the details on cost advantages achieved as well as future direction for further reduction in fresh water usage on a project basis.
Determining Propped Fracture Width from a New Tracer Technology
Authors: McDaniel R. R. , Holmes D. V. , Borges J. F. , Bajoie B. J. , Peeples C. R. , Gardner R. P. 
Published: January 2009

Abstract
An accurate determination of propped fracture geometry will help optimize the benefits derived from a hydraulic fracturing treatment. While advancements in determining propped fracture height have been made recently, there has been no new technology introduced addressing the other aspects of propped fracture geometry.
A new tracer technology has been recently introduced and field tested. This technology incorporates a non-radioactive tag into the coating of a resin coated proppant. The tagged proppant is non-hazardous and environmentally safe. The tagged proppant is activated (after it has been placed in the fracture) by a logging tool that contains a neutron source. The activated tag emits gamma rays at a characteristic energy level that can be detected by the logging tool. Analysis of the data (from the logging run) not only identifies the location of the tagged proppant, but can also be used to develop other valuable information including propped fracture width in the near wellbore region.
The resin coated proppant containing the tag is manufactured in such a manner as to assure that the concentration of the tag in the coating is held at a constant throughout the coating process. Since the level of gamma ray emission is a function of the amount of tag irradiated by the logging tool, the count rate detected by the tool is proportional to both the concentration of the tag and the concentration of the tagged proppant that has been irradiated. Based on these factors, analysis of the logging data not only yields the location of the tagged proppant, but leads to a more accurate calculation of the propped fracture width as compared to previous methods.
This paper will detail the test procedures and resulting data that contributed to the development of this new method to calculate propped fracture width. This method of propped fracture width calculation will then be applied to a variety of actual field applications of the tag technology. The calculated propped fracture width results from the field tests will be presented and discussed in detail.
Are You Buying Too Much Friction Reducer Because of Your Biocide?
Authors: Rimassa Shawn M. , Howard Paul R. , Arnold Michael O. 
Published: January 2009

Abstract
Slickwater fracturing is a large portion of current stimulation treatments in tight gas reservoirs. The fluids typically contain only friction reducer and biocide. They are considered incredibly simple, with little attention paid to their composition beyond the effects of water quality. In many cases, the biocides are sold and added to the fluid stream by production chemical companies while the friction reducers are added by the service company performing the fracture treatment. The paper reviews the chemical interactions between the typical anionic friction reducers and the cationic biocides such as quaternary ammonium compounds. The impact of these biocide-friction reducer interactions is that both materials are consumed and therefore prevented from performing their desired functions. During a treatment this is not obvious, but additional friction reducer eventually must be added to control pumping pressure. Further, the biocide is expected to be unavailable to control bacteria. The goal of any stimulation fluid should be that all components are compatible. As expected, some biocides complex with the oppositely charged friction reducers. This results in the formation of flocks of insoluble polymers in the fluid. Laboratory testing and a field example indicate that the quaternary ammonium biocides reduce the drag reduction seen with the common friction reducer. In comparison, nonionic biocides such as gluteraldehyde do not interact with the friction reducer. The paper also reviews studies with compatible scale inhibitors.
Operators Evaluate Various Stimulation Methods for Multizone Stimulation of Horizontals in Northeast British Columbia
Authors: Thompson Dave , Rispler Keith , Stadnyk Shawn , Hoch Ottmar , McDaniel B. W. 
Published: January 2009

Abstract
Effective reservoir exploitation in tight-gas wells can be achieved by fracture-stimulating horizontal wells. A primary key to economic success when fracture stimulating horizontal wells is achieving the placement of propped fractures uniformly along the entire lateral section. This well completion strategy is becoming a more common method and is currently being used to effectively develop tight-gas reservoirs in northeast British Columbia, Canada.
This paper reviews different well completion and stimulation methods currently being applied in horizontal well stimulation in Northeast British Columbia, Canada. Specifically, the paper reviews horizontal well stimulation of the Montney formation that extends from northwestern Alberta into Northeastern British Columbia. Well construction and well completion strategy should be based on reservoir understanding and optimum stimulation design. This paper discusses a number of options for well construction and stimulation methods, including: packer isolation and frac sleeves, pump down bridge plugs and perforating guns, coiled tubing deployed bridge plugs and tubing conveyed perforating, and hydrajet perforating on CT with sand plug isolation. Evaluation and comparison of these different techniques include well construction, well completion including post-stimulation cleanouts, and post stimulation production analysis, including consideration of logistics, method reliability, and comparison of results.