bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Fracture Spacing and Sequencing in Horizontal Well Fracturing
Authors: Roussel N. P. , Sharma M. M. 
Published: February 2010

Abstract
The opening of propped fractures results in the redistribution of local earth stresses. In this paper, the extent of stress reversal and reorientation has been calculated for fractured horizontal wells using a three-dimensional numerical model of the stress interference induced by the creation of one or more propped fractures. The results have been analyzed for their impact on simultaneous and sequential fracturing of horizontal wells.
Horizontal wells with multiple fractures are now commonly used in unconventional (low permeability) gas reservoirs. The spacing between perforations and the number and orienation of transverse fractures all have a major impact on well production.
Our results demonstrate that a transverse fracture initiated from a horizontal well may deviate away from the previous fracture. The effect of the reservoir's mechanical properties on the spatial extent of stress reorientation caused by an opened crack has been quantified. The paper takes into account the presence of layers that bound the pay zone, but which have different mechanical properties from the pay zone. The fracture vertical growth into the bounding layers is also examined.
It is shown that stress interference, or reorientation, increases with the number of fractures created and also depends on the sequence of fracturing. Three fracturing sequences are investigated for a typical field case in the Barnett shale: (a) consecutive fracturing, (b) alternate fracturing and (c) simultaneous fracturing of adjacent wells. The numerical calculation of the fracture spacing required to avoid fracture deviation during propagation, for all three fracturing techniques, demonstrate the potential advantages of alternate fracture sequencing and zipper-fracs to improve the performance of stimulation treatments in horizontal wells.
Significance of Selected Set-up Parameters in Return Permeability Measurements Used for Formation Damage Quantification
Authors: van der Zwaag C. H. , Olsen H. , Lohne A. 
Published: February 2010

AbstractInformal visits to formation damage laboratories in Europe and the United States, as well as reviews of literature and discussions with colleagues in other countries have shown that laboratory methods and equipment layout vary significantly from lab to lab. We have noted two important differences related to 1) Core holder design, and here especially core holder position either vertical or horizontal, and 2) Saturation procedures to establish initial water saturations Swi either by flooding or by centrifuging.Statoil has during the past 3 years reviewed internal requirements to formation damage laboratory measurements. Within this process, the impact of core holder design and saturation preparations was studied experimentally and by numerical simulation. This paper presents the results of laboratory return permeability measurements and core plug scale simulations systematically performed on- High (~1500 mD) and moderate permeability (~50 mD) outcrop core plug samples- With initial water saturation Swi established by flooding or by centrifuging- Using a 1.56 s.g. [13.0 ppg] high performance water-based mud- A test set-up with variable core holder position: vertical and horizontal.The measurements showed significant differences in return permeability related to the saturation preparations. Core holder position also had a significant impact on the measurements, yet only on those core plugs that were prepared to Swi by flooding. Numerical simulations showed that gravity degradation, in particular in high permeabilities, may affect the distribution of heavy brine based fluid filtrates depending on horizontal or vertical core holder position under otherwise equal capillary pressure conditions.The results of the study helped understanding historical return permeability data produced in different experimental setups. They lead to adjustments of requirements in internal "Best Practice"-type steering documentation and will be offered for presentation and discussion in relevant workgroups within the ISO-system that currently works on revised standards for measurements on reservoir drilling and completion fluids.
Mitigation of Formation Damage Caused by Water-Based Drilling Fluids in Unconventional Gas Reservoirs
Authors: Lakatos I. , Bodi T. , Lakatos-Szabo J. , Szentes G. 
Published: February 2010

Abstract
The detailed laboratory studies have been carried out with the aim at restricting the spontaneous imbibition and penetration of drilling fluids in tight sand gas and BCGA reservoirs. The measurements were extended to natural cores having permeability between 1 and 0.001 mD. It was found that because of the unusual pore structure and water-wet character of the cores extremely high capillary forces predominantly determine the flow and spontaneous imbibition phenomena in natural cores obtained from unconventional gas reservoirs. Based on the experimental results, it was clearly indicated that the water is a natural blocking phase, causing serious formation damaging hard to cure. Consequently, the fluid penetration from drilling fluids can be modified only by surface (interfacial) tension lowering and wettability alteration (from strongly water-wet to intermediate or oil-wet state). In addition, proper selection the cake forming components may significantly decrease the liquid uptake in tight, low permeable sandstones. The laboratory studies proved that using special surfactants, organic water miscible solvents and special high molecular weight additives the spontaneous imbibition and penetration of liquid phase of the water-based drilling mud can significantly be influenced in unconventional gas reservoirs mitigating thus the formation damage often encountered in tight sands and BCGA.
Stimulation of Multilayered High-Carbonate-Content Sandstone Formations in West Africa Using Chelant-Based Fluids and Mechanical Diversion
Authors: Parkinson M. , Munk T. , Brookley J. , Caetano A. , Albuquerque M. , Cohen D. , Reekie M. 
Published: February 2010

Abstract
Matrix stimulation of high-temperature sandstones using hydrochloric acid (HCl) is difficult to achieve due to its fast reaction, possible sand deconsolidation, clays destabilization, and tubular corrosion. These problems are common in stimulating wells completed across the Pinda formation in West Africa. This formation is a multilayered formation with a wide range of carbonate content (varying from 2% to nearly 100%) and bottomhole temperatures in the range of 300°F. In addition, most of the wells have up to 1,500 ft of perforated intervals producing together from different layers. Stimulation treatments in the area historically have been performed using 7.5% HCl pumped through coiled tubing and using foam diversion.
In 2008 a different approach was taken to stimulate producing zones across this formation, using a low-pH chelant (pH 4) as the main stimulation fluid and straddle or inflatable packers for mechanical diversion, whenever applicable. Six wells were treated in a stimulation campaign using the chelant solution. Mechanical diversion was used in three of the six wells treated; two were treated with a mechanical straddle packer and one with an inflatable packer. Low bottomhole pressure (BHP) or wellbore configuration precluded the use of mechanical diversion for the other three wells; foam diversion was used instead. The results of these stimulations were encouraging, with the combined production of all six wells almost doubling. The good post-job results confirm the effectiveness of low-pH chelant in stimulating carbonate and carbonate-rich sandstones at high temperature, with the added value of low corrosion rates and reduced risk of sand deconsolidation and clays destabilization.
This stimulation campaign also tested current technological limits of mechanical and inflatable packers. The combination of high expansion ratio, low BHP, and high temperature requirements precluded the stimulation of three of the six wells with mechanical diversion. With the increasing need to stimulate depleted high-temperature formations, these challenges must be addressed in the future.
Expandable Screens: Field Cases in Deepwater Environment
Authors: Degos X. , Furgier J-N. , Dufour P. , Marpaung F. , Bourgoin S. 
Published: February 2010

Abstract
Expandable screens are a relatively new technique in the industry. Recently, three typical cases of expandable screen applications were presented in the SPE paper 121543. The present paper focuses on deepwater case histories of expandable screen applications within TOTAL.
Deepwater projects are challenging, high profile jobs. Reliability and robustness are key factors in selecting the right sand control techniques. So the benefits of using of expandable screens must be plain so as to offset the reluctance of introducing this relatively new technique.
Large deepwater developments started for TOTAL in 2000 in West Africa. On those projects and since, the typical development scheme for unconsolidated, uniform, medium-size sand fields, has been:
- Horizontal oil producer completed with Stand Alone Screens. - Deviated oil producer completed with either Stand Alone Screens or Frac-Pack completions (depending on reservoir characteristics). - Horizontal and deviated water injector completed with Stand Alone Screens.
That typical deepwater scheme now introduces expandable screens in:
- water Injectors for deviated wells, and - oil producers for deviated wells.
This paper offers feedback and insight on case histories from West African projects. It details the installation process (mud, cake treatment, and expansion aspects in application from floating rigs), the limitations and the performances.
Reservoir Characterization Using Injection Test After-Closure Analysis: Field Case History in a Depleted Oil Reservoir
Authors: LeBlanc G. , Gunasan E. , de la Combe J-L. Boutaud , Jaffrezic V. 
Published: February 2010

Abstract
Hydraulic fracturing is being employed on more complex and lower permeability fields, making the associated reservoir characterization increasingly complex and difficult. Various methods exist to determine reservoir transmissibility (kh/µ), each with their own strengths and limitations. Well testing, pre or post-frac, on offshore depleted oil reservoirs is often uneconomical and can be problematic, while quantifying the productive height in laminated oil reservoirs is equally difficult. This paper will present field case histories demonstrating the successful application of after-closure analysis in various reservoir types along with highlighting the benefits and limitations of the process.
The use of after-closure analysis during diagnostic fluid injection tests (DFIT) is a well known method of determining reservoir transmissibility. This method enables linear and radial flow regimes to be identified, thus determining reservoir transmissibility. To further strengthen the process, this paper proposes a multidisciplinary approach that combines the after-closure methodology with conventional well test diagnostics.
Our results showed that we could successfully quantify reservoir transmissibility using after-closure analysis and yield the same results as well test analysis. Furthermore, these results were confirmed with post-frac well test analyses. Moreover, quantifying reservoir pressure prior to the injection test was the key to an effective design in under-pressured reservoirs.
We have shown that our multidisciplinary approach to after-closure analysis yields consistent results in determining reservoir transmissibility in actual field cases. Some operational and technical constraints were identified; some have been resolved while others still remain. Notably, using oil as a slightly underbalanced fluid ensured a pressurized wellbore which sufficiently extended falloffs such that a proper analysis could be conducted. In conclusion, after-closure analysis provides a powerful tool for reservoir characterization in complex reservoirs.
Nanoparticle Pseudocrosslinked Micellar Fluids: Optimal Solution for Fluid-Loss Control With Internal Breaking
Authors: Huang T. , Crews J. B. , Agrawal G. 
Published: February 2010

Abstract
Micellar fluids with viscoelastic behavior, or viscoelastic surfactant fluids, are used in the oil industry as completion and stimulation fluids. The viscoelastic (i.e. viscous and elastic) behavior of these fluids is based on the overlap and entanglement of very long worm-like-micelles. High fluid leak-off has, however, limited their application for hydraulic fracturing and frac-packing applications. Recent developments have found that micellar fluids can have wall-building leak-off control similar to crosslinked-polymer fluids (CPF) by the addition of a small amount of inorganic crystals that are less than 100 nanometers in size (i.e. nanoparticle).
This paper will investigate the mechanism of fluid loss control for the particle-micellar fluid system. The tiny particles have high surface force, including van der Waals and electrostatic forces. The nanoparticle surface forces pseudo-crosslink the elongated micelles, which is similar to crosslinking polymers. The unique pseudo-crosslinking of surfactant micelles and particles has demonstrated improved viscosity, the formation of a filter cake, and enhanced thermal stability. Laboratory tests show the development of a filter cake significantly reduces the rate of fluid loss and demonstrates wall-building rather than viscosity-dependant leak-off control. Two models of static fluid loss control for particle-polymer fluid system will be reviewed. Fluid leakoff characteristics will be compared between the particle-micellar fluid system and particle-polymer fluid system.
Uniqueness of this system is that the fluid loss control was achieved without compromising the internal breaking efficacy. Ordinarily additives 'plasticize' the micellar or colloidal aggregates. However, through our patented processes, we were able to successfully place the internal breakers inside the elongated micelles so as to not interfere with particles' pseudo-crosslinking. When internal breakers are activated by temperature, the elongated micelle structure collapses thereby significantly reducing the fluid viscosity and thus breaking down the filter cake into tiny particles. This results in clean breaking gel with reduced damage to formation permeability and fracture conductivity.
Archives of Wellbore Impression Data From Openhole Vertical Well Fracs in the Late 1960's
Authors: McDaniel B. W. 
Published: February 2010

Abstract
During the timeframe of the mid- to late 1960's, a large number of those working in the Oil and Gas industry were still of the mindset that most hydraulic fracturing treatments were creating horizontal fractures, although the bulk of the technical papers still available from this time period seem to mostly assume or even verify vertical fractures. This view seemed especially prevalent for the numerous sandstone reservoirs that contained thin laminations of shale or shaley sand that seemed to have only very weak bonding to the adjacent sand layers. Many of this group had been present when such a formation was being cored, and observed the core sample simply separate at a (horizontal) bedding plane interface or a thin shale streak when the core would be removed from the core barrel. Many others had read more than one core analysis report containing similar descriptions of this occurring to cores when they were being tested.
This misguided "horizontal fracturing concept" was almost always in disagreement with observed pressure data during fracturing operations. Although pressure gradients during breakdown of cased and perforated wells occasionally would approach the reservoir's overburden pressure, fracture extension pressures almost never would.
Starting in about the mid-1960's, in an effort to enhance acceptance among the "rank and file" group in oilfield operations that vertical fracture orientation was both expected and actual outcome for almost every well, or at least when deeper than the 1,500 to 2,000 ft range at least one service operator and numerous well operators joined efforts to make rubber impression molds of openhole wellbores immediately after the well had been proppant-fracture stimulated. This was soon followed by adding a method to identify the compass orientation and investigate a more technical purpose: to document the fracture direction.
Unfortunately, only a small part of the resulting pictorial data base was ever published into the preserved public domain during the decade of their significant use. This paper will revisit the few known papers within the literature and also data archives preserved in internal company reports and by nearly a hundred photographs of created rubber wellbore molds following openhole hydraulic fracture treatments. These show the resultant propped fracture traces inside wellbores from more than a dozen openhole applications of this simple technology. Such results as fractures (at 4O to 8O angles off of vertical) may only be present inside the wellbore for a few feet, and numerous cases of clear evidence of two and three separate parallel propped fracs present at least at the wellbore wall.
Micron Rating and Quality Assurance of Woven Metal Mesh Material for Premium Sand-Control Screens
Authors: Underdown D. R. , Kenney R. 
Published: February 2010

Abstract
On of the major issues associated with quality assurance of woven metal mesh material for premium sand control screens is accurate and precise measurement of the micron rating. Standard tests for characterizing filter media are established by national authorities such as the British Standards Institute (BSI), American Society for Testing Materials (ASTM) and the International Standards Organization (ISO). The standards typically define in detail recommended testing equipment, methods of operation and procedures for processing and interpreting the data. The challenge is selecting the appropriate test and methodology to provide a meaningful micron rating to woven metal mesh filter media used in premium sand control screens.
One of the more common methods of measuring the micron rating of woven metal mesh material for premium sand control screens is known as the "glass bead" test. There are several variations of this test method used throughout the industry without any standardization. Therefore, it is difficult to use this or any other method to obtain a micron rating for quality assurance of a woven metal mesh unless the end user understands the limitations of the method used in the measurement and consistently uses the same source for the information. This paper discusses the pros and cons of the various methods of measuring micron ratings. The consequence of using only the micron rating of a woven metal mesh for premium sand control screens is also discussed
When Do Surfactant-Based Acids Work as Diverting Agents?
Authors: Al-Ghamdi A. H. , Mahmoud M. A. , Hill A. D. , Nasr-El-Din H. A. 
Published: February 2010

Abstract
The purpose of matrix stimulation in carbonate reservoirs is to bypass the damaged zones and increase the effective wellbore area. This can be achieved by creating highly conductive flow channels known as wormholes. A further injection of acid will follow the wormhole path where the permeability has increased significantly, leaving substantial intervals untreated. This problem can be significant as the contrast in permeability increases within the target zones. Diverting materials such as surfactant-based acids play an important role in mitigating this problem. Several papers published in the literature aimed to verify the diversion capability and the performance of the self-diverting acids. However, most of the parallel-coreflood experiments, if not all, used relatively short cores (2 to 6 inches in length).
In this paper, acidizing experiments were conducted using two 20-inch long cores with different permeabilities. Carbonate cores were used with a permeability of 5 to 150 md and the total flow rate was varied from 3 to 20 cm3/min. The initial contrasts in permeability between the two cores ranged from 2 to 15 fold. To characterize the wormholes generated, a computerized tomography (CT) was used to generate 3-D images to describe the shape of the wormholes in both cores.
Several periods were identified from the shape of the flow rate distribution entering each core. Acid injection rate was found to influence the efficiency of surfactant to divert acid. Acid diversion was noted to be most efficient at low flow rates (3 cm3/min). No significant diversion was noted at higher flow rates (&gt; 6 cm3/min). Also, no significant diversion was noted at high initial permeability ratios at least for the given core length. In conjunction with the experimental study, an analytical model was developed to verify the experimental results obtained with regular acids.
Post-Fracturing Fluid-Recovery Enhancement With Microemulsion
Authors: Agee D. , Yudho A. , Schafer L. , Thouvenin E. , Grant G. , Garnier A. , Wijanarko A. 
Published: February 2010

Abstract
The fields of East Kalimantan, Indonesia contain several depleted gas zones of medium permeability (0.1 to 300 mD). Though the permeability is quite good for gas bearing formations, the majority of the wells targeting these sands have failed to produce at expected rates. In the 1980s, hydraulic fracturing was introduced to the area in an attempt to increase production. The treatments yielded limited success with many wells actually producing less after being fractured. This led operators in the area to believe that the formations could be water sensitive with damage from the injected fluids causing the poor results after fracturing. As laboratory testing has ruled out water-sensitive mineralogy, the suspected cause of damage has been attributed to a decrease in relative permeability to gas after the fracturing fluid has penetrated the pore throats (water block). The water block conclusion is supported by the low percentage of injected fluids that are returned after the treatment.
In 2007, VICO performed four fracturing treatments using a conventional surfactant to aid in post-frac cleanup. Only 2 of the 4 wells that were fractured produced after the treatment. Again, a common problem between the wells was the poor return of treatment fluids during cleanout. The limited success of these treatments indicated the water block issue had not been resolved. After reviewing the results of the first four wells, three additional fracturing treatments were placed in similar reservoirs using a microemulsion additive instead of the surfactant. Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al. (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions.