bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Evaluation of RDF Breakers Under Linear and Radial Flow Conditions
Authors: Marquez M. , Lenz R.
Published: February 2010

Drilling-induced formation damage is an area of concern when it comes to wellbore productivity, particularly for highly deviated / horizontal open hole completions. A great deal of effort has been devoted to understanding the damage mechanisms associated with Reservoir Drill-in Fluids (RDF), and to develop systems to specifically target bio-polymers and bridging agents in the RDF cake for improved wellbore clean-up. Experimental techniques to evaluate the performance of RDF clean-up treatments, however, have not received much attention. Due to its simplicity, the High Temperature High Pressure (HTHP) cell has been widely adopted by the Industry as a standard method to evaluate the performance of RDF filter cake stimulation treatments, but this technique has a number of limitations in terms of the quality and reproducibility of the deposited filter cake, as well as its ability to predict flow initiation pressure and return to flow percentage after the stimulation treatment.

This work compares the performance of two commercial RDF breakers in a GP application, under linear and radial flow conditions, using a HTHP cell and the Dynamic Displacement Radial Permeameter (DDRP) device described by Davidson et al. (2006). Unlike the HTHP cell, the DDRP cell can be arranged such that the RDF deposition, displacement, and stimulation stages of a horizontal Open Hole Gravel Pack (OHGP) can be simulated dynamically and sequentially, without system disruptions. The breakers evaluated are combinations of polymer-specific enzymes, chelating agents, and acid. Breaker "A" is a buffered acid system, while Breaker "B" contains a slow release acid precursor. The clean-up efficiency of each breaker, relative to a control system with no breaker, was determined as a function of flow rate using the DDRP device. These results were compared to those obtained under linear flow conditions with the HTHP cell. Significant differences were observed between the flow initiation pressure values measured with the HTHP cell and those measured with the DDRP, particularly for the system with no breaker. Differences were also observed in terms of percentage return to flow; higher percentages were consistently measured with the DDRP device. The difference between the percentage return to flow measured with the HTHP cell and the DDRP device was less than 5% for the system with no breaker, and 20% to 55% for the systems treated with the breaker solutions. In general, linear flow tests with the HTHP cell are useful as a pre-screening tool, but more sophisticated equipment such as the DDRP device can simulate downhole flow patterns and cake deposition more accurately and reproducibly. They also provide insight to important design parameters such as breaker activation time and flow rate dependencies of the clean-up treatment.
A Novel Technique for Achieving High Rate Water Injection at Matrix Rates In Openhole Sand Control Completions: A Case History from Akpo Field, Nigeria
Authors: Marpaung Fivman , Bourgoin Sebastien , Bagal Joseph , Deffieux Damien , Beldongar Maye , Patey Michael , Gadiyar Bala , Parlar Mehmet
Published: February 2010

Many of the water injectors in sand control environments are being completed as long open holes due to higher injectivities attainable with such completions. Although target rates may often be achieved without any cleanup chemicals in production wells, injection wells require filtercake cleanup, in cases whereproducing the well prior to injection is not feasible or desirable, (e.g., limited storage capacity on the rig, or artificial lift requirements due to low pressure or injection into water leg)injecting above frac pressure is either not feasible (e.g., very high frac pressures and pump limitations) or not acceptable (e.g., sweep efficiency, premature water breakthrough, uncontrolled fracture height growth).

Although a large variety of filtercake cleanup techniques and chemistries are available in the industry, most of these solutions are effective in producers. As demonstrated through laboratory experiments, achieving consistently high injectivities requires removal of drill solids from the filtercake, through either dissolution (e.g., acid formulations utilizing HF) or effective displacement techniques that will not result in injection of these solids into the formation pore throats (SPE 77449). In addition, an effective filtercake removal (including drill solids) in long open holes without inducing high losses into the formation (so that the wash pipe can be pulled out and a mechanical fluid loss control valve can be activated) remained as a formidable challenge, which becomes even a bigger challenge in wells drilled with conventional oil based muds (OBM), particularly in reactive shale environments.

In this paper, we present a novel technique that addresses these challenges, proven through field application on a standalone screen water injector in Nigeria. The technique involves displacement of OBM from openhole with a viscous spacer pill containing a demulsifier, followed by completion brine containing a mutual solvent to weaken the filtercake without attacking the bridging agents, subsequently performing a high rate viscous pill displacement to remove the external cake, and finally spotting a water-based self-destructive fluid loss control pill to control the losses while pulling the wash pipe. Laboratory testing for designing the displacement stages, field execution, and well performance evaluation are detailed.
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

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

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

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

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

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

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

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

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

High-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

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

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

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

Informal 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

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

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

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

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

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

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

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