bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combining Stimulation and Water Control in High-Water-Cut Wells
Authors: Jaramillo O. J. , Romero R. , Lucuara G. , Ortega A. , Milne A. , Lastre M. 
Published: February 2010

Abstract
A brownfield in Colombia, produces from the Caballos formation, a highly laminated sandstone formation with permeability of 50 to100 md. The field is under water injection, resulting in calcium carbonate scaling; thus, these wells need to be acidized routinely although the water cut often exceeds 90%. Initially, straddle packers were used to divert the treatments mechanically across the laminated sands, which required a workover rig.
To reduce the cost of treating these wells, recent treatments were bullheaded down the tubing casing annulus at the highest possible matrix rates, resulting in mixed results. Water cut increased with no or an insignificant increase in oil production. Hence, a diversion technique/fluid was needed that would provide effective zonal coverage similar to that obtained using straddle packers. The viscous disproportionate permeability modifier (VDPM) fluid was developed for this application. The initial treatments, performed by pumping alternate stages of acid and a VDPM fluid, increased oil production as much as 300% while reducing the water cut by up to 10%. In these cases, the increase in production is equal to or better than wells treated selectively with straddle packers.
The use of a VDPM fluid has been shown to be capable of improving zonal coverage, increasing oil production, and decreasing water cut in formations without natural fractures or fissures. During the treatment, the treating pressure increases or remains constant while, in core flow tests, the pressure increases sequentially when injecting acid after each stage of diverter. Despite this, the final effective permeability to oil increases and the effective permeability to water decreases significantly. The VDPM fluid reduces the effective permeability to water up to 80% in a water-saturated core. In the field, the permeability and the length of the interval(s) to be treated determine the number, volume, and viscosity of the VDPM fluid stages based on previous core flow studies.
The use of the VDPM fluid has the potential to increase the economic viability of producing this particular field in Colombia and other similar fields. The properties of the VDPM fluid are particularly advantageous when repeatedly treating wells in mature fields on water injection.
Particle Consolidation as a Means of Sand Control: Gulf of Mexico Applications
Authors: Oubre B. , Hasemann A. 
Published: February 2010

Abstract
Particle movement is a problematic occurrence for wells producing in the Gulf of Mexico (GOM). The particles could be formation sands or proppant. The most widely used and most effective method of sand control in the GOM is the mechanical method. The mechanical method used in most wells includes the use of screens with a proppant pack. An alternative to the mechanical method is the chemical-consolidation method. With this method, the particles are bonded together to prevent movement. This paper describes chemicals and treatments that can be used to consolidate downhole particles as well as explains scenarios in which these materials can be used.
Chemical consolidation has many applications in unconsolidated-reservoir environments. One application is to use this technology to consolidate the formation in the near-wellbore region, which would be suitable as the only form of sand control. Another application would be to use these chemicals for screen repair. When the well is producing proppant and formation sand because of a damaged screen, consolidating the proppant pack around the screens is a proven way to stop the particles from flowing. Both of these techniques involve injecting chemicals into the well. Instead of consolidating with a chemical injection, proppant particles can also be coated with chemicals on the surface during pumping of the proppant-stimulation treatment.
The results that can be observed from these treatments demonstrate that produced solids can be eliminated. The production data of wells that have used these chemicals to measure the effectiveness of the treatments were compared. From the data presented, it can be concluded that these treatments provide additional options for completing or repairing wells that require sand control. The data also demonstrates ways to stop solids from being produced with well-intervention treatments.
This paper explains a variety of ways that particle-consolidation chemicals can be applied, along with a general description of the materials used. Lab data associated with these chemicals is presented. Use of this technology is discussed in detail, including several case histories in the GOM.
Distinguishing Filtration Mechanisms by X-Ray Tomography: Quantification of Simultaneous Internal Deposition and External Filtercake Buildup in Sandstone
Authors: Obeta C. C. , de Zwart A. H. , Currie P. K. 
Published: February 2010

Abstract
Many oil-field 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 suffer from injectivity decline. This injectivity decline is caused by clogging of the formation by particles, which form an external filter cake on the surface of the formation and block the pores inside the formation.
This article reports on a set of crossflow experiments in which a suspension of particles is flowed over the surface of a sandstone core, with a portion of the suspension entering the core itself. An external filtercake is formed on the surface of the core, and internal deposition occurs inside the core. The experiments are conducted in a CT scanner, allowing measurement of the internal deposition in real time. Thus, although the time-dependent build-up of the external filtercake thickness cannot be measured directly, it can be deduced by mass balance, allowing for the crossflow and permeant effluents. This enables correlation of the external and internal mass deposition with the measured increase in injection pressure.
We use the cumulative mass curves of the hematite deposited in the cake, core and in the effluent to model the dependence of the pressure drop on cake and core deposition, and compare the predicted pressures with the actual measured pressures.
These results are very relevant to operational issues associated with injection or leak-off, including hydraulic fracture propagation, drilling-mud impairment and produced water matrix re-injection. The results are also relevant to water injection under fracturing conditions, since impairment of the wall of the fracture is one of the mechanisms governing fracture growth, and the implications of the results for this process are discussed.
Impact of Water Dynamics in Fractures on the Performance of Hydraulically Fractured Wells in Gas Shale Reservoirs
Authors: Cheng Y. 
Published: February 2010

Abstract
Slick water fracturing has been increasingly applied to stimulate unconventional gas shale reservoirs. Comparing with cross-linked fluids, slick water used as a fracturing fluid has several advantages. Among them include low cost, higher possibility of creating complex fracture networks, less formation damage and easy-to-cleanup. Enormous amount of water is injected into the formation during the treatment. Even with a good recovery of injected water from flowback, large quantities of water are still left within the reservoir.
The dynamics of water phase within the created hydraulic fractures and reactivated natural fractures (induced fractures) have significant impact on both short and long term performance of a hydraulically fractured well. The dynamics of water phase within fractures are controlled by many mechanisms, such as relative permeability, capillary pressure, gravity segregation and stress-sensitive fracture conductivities. In this paper, reservoir simulation models for a generic gas shale reservoir are constructed to investigate the changes of water saturation distribution in fractures over time during the production and their impact on gas production performance. It is demonstrated that water imbibitions due to capillary pressure and gravity segregation can play important roles in water saturation distribution and redistribution, particularly during extended shut-in, which in turn affects gas flow significantly. Moreover, unfavorable combination of relative permeability, capillary pressure, stress-sensitive fracture conductivities and invasion zone permeability damage can lead to water blockage problems.
Limits of Well Deviation to Prevent Screen Erosion in Cased-Hole and Frac-Packed Wells
Authors: Wang Xiuli 
Published: February 2010

Abstract
For high permeability, loosely consolidated reservoirs, cased hole and frac packed (CHFP) completions have been employed for both sand control and production stimulation. More often than not, these wells are offshore and are drilled deviated or highly deviated from centralized platforms.
Because fractures are almost always vertical with a very well-defined azimuth, fractures executed in deviated wells have very inefficient contact with the wellbores. This means only a few perforations are actually connected to the fracture even with the so called halo effect. As a result, a large portion of the total rate bypasses the fracture and enters the well through the perforations that are not in contact with fracture. For example, at 10,000 STB/d with permeability of 50 md, the fractional flow through the fracture is 64% even for a 10° well deviation. It drops to only 30% for a 45° well deviation. This provides different velocities, different erosion C-factors (15.6 vs. 39.2 through the fracture region and 1.4 vs. 1.9 for the rest, respectively) and different sand control characteristics between the two sets of perforations.
A limited number of perforations connected to the fracture means that the velocity through them, for a given production rate, is high. This could cause fine movement which would further cause screen plugging and screen erosion. When the screen is partially plugged, it is more prone to erosion simply because the screen inflow area is reduced and therefore (at the same flow rate) the fluid velocity increases. Screen erosion can be more severe at one well deviation angle than another.
Here the number of opened perforations in the deviated wells and a range of C-factors for different well production rates (i.e. for different reservoir permeabilities and well deviations) are calculated. These C-factors are compared with published experimental and field data. It appears that they frequently exceed the maximum C-factor of screen erosion. Finally, guidelines on acceptable well deviations that will not lead to screen erosion are offered.
Modeling Fluid Invasion and Hydraulic Fracture Propagation in Naturally Fractured Rock: A Three-Dimensional Approach
Authors: McLennan J. , Tran D. , Zhao N. , Thakur S. , Deo M. , Gil I. , Damjanac B. 
Published: February 2010

Abstract
It has progressively become more accepted that fracture growth, particularly in extremely low permeability, naturally fractured reservoirs cannot be reliably represented by conventional planar simulations. Characterizing evolution of multiple, non-planar, interconnected, and possibly non-vertical hydraulic fractures requires hydraulic and mechanical characterization of the nominally intact matrix as well as existing latent or healed fracture networks. This paper describes an approach to representing and assessing complex fracture growth and associated production prediction through this generated fracture. There are three stages in this protocol. The first is a representation of the fracture networks. The second is importing this DFN (discrete fracture network) into a coupled geomechanical simulator and representation of fracture evolution. The final step is importing the resultant conductive system into a multiphase DFN reservoir simulator for the prediction of production rates and the generation of pressure and saturation maps.
The complex fracture network evolution during stimulation is represented using a Discrete Element Method, DEM – starting from the representation of a naturally fractured reservoir and modeling complex, non-planar, hydraulic fracture propagation. A representative fracture network was used under a variety of conditions.
The objectives of this modeling include: 1) assessing the effects that operational parameters (such as injection rate) have on the volumetric extent of the fracture system or domain and the extent of fluid penetration in the natural fractures; and 2) assessing the degree of water blocking and loss of conductivity in the fracture system using a DFN reservoir simulation model. Both these issues are crucial for treatments in shale gas systems.
Delayed-Release Coatings for Oxidative Breakers
Authors: Watson W. P. , Aften C. W. , Previs D. J. 
Published: February 2010

Abstract
Inorganic and organic coatings for solid oxidative breakers have been developed to degrade slickwater and gelled stimulation fluids, reducing the polymers’ potential to cause formation damage as they concentrate in fractures. The coatings result in a delay of 90 minutes or more before the oxidizer begins to degrade the frac fluid, and this benefit was obtained without compromising the properties of the stimulation fluid or the oxidizer.
Frac fluids consist of ultrahigh molecular weight synthetic polymers or functionalized or unadulterated polysaccharides, and can be crosslinked by borates, zirconates, titanates, or other species. The high viscosities of these fluids allow proppants to be transported, or, in the case of slickwater fracs, provide drag reduction, diminishing the amount of energy needed to pump the fluid. After the shut-in period, however, the polymers’ presence can be problematic, creating a skin over the newly formed fracture surface and proppant bed, reducing the communication from the wellbore to the fracture/formation. Breakers such as oxidizers and enzymes have been employed to degrade polymers, each with their own strengths and weaknesses. Oxidizers quickly and effectively attack a wide range of synthetic polymers and polysaccharides, while enzymes work in a more controlled fashion and have to be tailored for specific fluid systems.
In order to avoid premature degradation of stimulation fluids, breakers can be added towards the end of the shut-in period, or encapsulated and added earlier. Static and dynamic benchtop tests were conducted on polyacrylamide copolymers and linear polysaccharide gels over a range of temperatures, and the new coatings were observed to increase the time to a full break by a minimum of 90 minutes, depending on the thickness and composition of the encapsulation layer. Ultimate performance enhancement was gained within reasonable cost constraints.
Optimization of Multiple-Fractured Horizontal Tight Gas Well
Authors: Bagherian B. , Sarmadivaleh M. , Ghalambor A. , Nabipour A. , Rasouli V. , Mahmoudi M. 
Published: February 2010

Abstract
Horizontal drilling and hydraulic fracturing are two reliable technologies which have made recovery of tight/shale gas economically viable. A common practice is to drill horizontal well parallel to the minimum horizontal stress, consider short perforation intervals and hydraulically fracture the formation. It is expected that the created fractures would be perpendicular to the horizontal well (transverse fractures).
Determining the number of fractures in such horizontal wells is of great interest by the industry. Although one may assume that the more the number of fractures the better the productivity, there is always an optimum number of fractures (hence optimum fracture spacing) which is obtained based on both production rate of the reservoir and its cumulative production.
In this paper, different sensitivity analyses on physical optimization parameters are combined by economical evaluation to find the optimum value of fractures spacing (number of fractures), and the length of horizontal section. These optimization analyses have been done on horizontal section length, total permeability, anisotropic permeability ratio, and drainage area. Analyses have been performed based on the values of gas production rates, cumulative production, and defined K value. Finally, economical optimization which was performed using U.S. historical monthly gas prices, inflation and interest rates over a period of 27 years, was coupled with production data obtained from modeling. All the costs and revenues were converted to U.S. Dollar value in 2009. This evaluation shows that for each specific reservoir an optimization study is required and there is no unique solution for all types of reservoirs. However, the gas price forecast is the main factor which governs the whole optimization process.
Long-Term Production Results of High-Rate Water Packs: Case Histories from Nanhai West Bay, South China Sea
Authors: HaiMing W. , Wah K. , Nguyen P. , Fleming J. , Lai E. 
Published: February 2010

AbstractHigh-rate water-pack (HRWP) completions frequently perform poorly in both hydrocarbon productivity and production endurance. This poor performance has been linked to pack-permeability damage caused by the fines invading the pack and migrating toward the wellbore. The NanHai West Bay reservoir is a sandstone formation with high C02 content. It exhibits moderate to high permeability and a high sanding tendency caused by weakly consolidated formation and high watercut. To access this reservoir, multiple wells from two separated platforms were completed in 2002 with HRWPs and extension packs (EPs). The EP completions used proppant that was coated with a surface-modification agent (SMA). This completion method was selected to bypass the near-wellbore damaged formation by creating wide and short propped fractures without fracturing into the nearby water zone. Completion tools consisted of 13Cr material because of high CO2 concentrations. A short and compact weight down-tool system was chosen so that the wells could be completed efficiently with limited rig space on unmanned platforms.This paper presents the long-term evaluation results of these wells and provides detailed descriptions of the completion procedures, challenges, and the difficulties during the course of these treatments. Field results of these HRWP- and EP-treated wells show that their productivity continues to hold up at levels better than expected, even after more than seven years of production. These wells continue to produce at low drawdowns without causing mechanical damage to the proppant packs and sand-control screens, despite the high sanding tendency, high watercut in the formations, and frequent exposure to stress cycling as the wells undergo production and shut-in.
New Predictive Model of Penetration Depth for Oilwell-Perforating Shaped Charges
Authors: Harvey J. , Grove B. , Zhan L. , Behrmann L. 
Published: February 2010

Abstract
For cased and perforated natural completions, well productivity depends strongly on perforation parameters. These include system parameters (shot density and phasing), and the characteristics of the individual perforation tunnels (depth extending beyond drilling damage, the nature of the crushed zone surrounding the tunnels, and to a lesser extent the tunnel diameter). This paper describes recent research directed at improving the accuracy of penetration prediction at downhole conditions.
Most conventional industry penetration models are based on laboratory experiments spanning the 1960’s through the 1990’s. It has been recently observed, perhaps not surprisingly, that these models are not always accurate predictors of the true downhole performance of modern shaped charge perforators. This situation is further complicated by the recent discovery that different industry models can give significantly different predictions of downhole penetration.
The authors have addressed this situation by conducting an extensive laboratory experimental program, using the results as the basis for developing significantly improved penetration correlations. The new correlations are based solely on stressed rock performance, no longer dependant on unstressed concrete targets. This test represents a significant departure from previous approaches, but one which is necessary in order to focus our attention to targets of relevance to the downhole environment. Furthermore, this paves the way for optimization of charges for certain downhole environments, rather than for unstressed concrete. Several hundred modern charges of different sizes have been shot into multiple rock types under simulated downhole stress conditions up to 20,000psi.
The new penetration correlation exhibits significantly improved accuracy in depicting the true influence of overburden stress, pore pressure, and formation strength on modern perforators. Consistent with historical work, we found that penetration depth in liquid saturated sandstones varies inversely with rock strength and applied stresses. Although the conventional models have been shown to be optimistic, this effort confirmed that the modern premium deep penetrator charges did outperform their predecessors at downhole conditions.
Additional experiments with gas saturated sandstones indicated that penetration depth was shallower and less sensitive to stress level than in liquid saturated sandstones. Stronger rocks exhibit less fluid dependence.
The improved correlations developed in this work are being implemented into the author’s penetration and productivity software. This will enable more accurate and reliable prediction of well performance.
State of the Art Screen Selection for Standalone Screen Applications
Authors: Chanpura R. A. , Hodge R. M. , Andrews J. S. , Toffanin E. P. , Moen T. , Parlar M. 
Published: February 2010

Abstract
Standalone screens (SAS) in openhole can provide highly reliable sand control completions at a lower cost and with less operational complexity than other openhole sand control completions as well as long term productivity performance comparable to other openhole completions, when applied in the "right environment with the right procedures." Although many in the industry would agree with the preceding statement, there is no consensus on what the right environment is and what the right procedures are. Even when there is agreement on the applicability of SAS for a particular sand size distribution, there are considerable differences in the recommended screen type and screen opening between various laboratories.
In this paper we critically review the various laboratory testing procedures used in the industry and the interpretations made to evaluate screen performance and screen selection for SAS applications. We demonstrate that the way some of the laboratory tests are performed are biased towards one type of screen (wire wrap) and some are interpreted without sufficient information such that they almost always favor another type of screen (premium mesh). We show that severe screen plugging with clean formation sand is almost never an issue and that the probability of screen plugging due to other factors can be minimized when proper precautions are taken. We propose that screen candidates for standalone screen applications be initially selected based on sand retention performance, with the final selection confirmed based on flow capacity. In addition, based on ~ 185 laboratory tests performed on various types of wire wrap (6 to 16 gauge) and premium mesh (60 to 600 µm) screens for unconsolidated sands and using a set criterion for sand retention, we conclude that many of the currently used criteria in the industry for selection between gravel packing and SAS are highly conservative, and unduly limit the possible application of standalone screens.