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Collaborating Authors
Well Completion
Abstract The field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). A comprehensive description is available on a previous publication1. The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field. As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation. Introduction The field was discovered back in 1974 by the exploration well 2, which was drilled in the southern part of the anticline that was delineated by seismic data. Commercial flow of oil was produced from the carbonate reservoirs of the "M" horizon that represents the uppermost portion of the Paleozoic basement2. The discovery has attracted a significant attention at the time, being a first demonstration of the productive potential of West Siberian basement3. In the next few years a series of medium and small size oilfields with pre-Jurassic reservoirs have been found in the southeastern part of the basin (e.g. Archinskoe, Chkalovskoe, Urmanskoe, Gerasimovskoe, and others). In all of these fields oil was produced from the basement carbonates and weathering crust. Further investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potential is mostly related to the basement limestones that have been significantly affected with secondary processes such as dolomitization, leaching, and fracturing4. Following the initial discovery, 19 wells have been drilled in the field, and 8 of them produced commercial oil rates. The results of core investigations and well test analyses showed that the productive unit "M" consists of a complex fractured vuggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines productive potential of wells. General information The basement of the field consists mostly of Paleozoic carbonates that also include some layers of siliciclastic and volcanic rocks. The overall structure of the field represents a elongated anticline of an irregular shape that is located northwest of Mezhov arch. Interpretation of 3D seismic data showed that the basement strata contain numerous nearly vertical faults (Fig. 2). The faults are rarely traceable above the top of Jurassic Tyumen formation.
- Asia > Russia > Ural Federal District > Tyumen Oblast > Tyumen (0.24)
- Asia > Russia > Siberian Federal District > Novosibirsk Oblast > Novosibirsk (0.24)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District (0.24)
- Phanerozoic > Paleozoic (0.65)
- Phanerozoic > Mesozoic > Jurassic (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.45)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.54)
- Geophysics > Seismic Surveying > Seismic Processing (0.47)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > Novosibirsk Oblast > West Siberian Basin > Maloichhskoye Field (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > Ghaba Salt Basin > Qarn Alam Field (0.99)
- Africa > Middle East > Tunisia > Kairouan Governorate > Pelagian Basin > Sidi El Kilani Concession (SLK) Permit > North Kairouan Concession > Sidi El Kilani Field > Abiod Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Abstract Surface modification agents (SMAs) and their coating onto proppant have been used in thousands of wells in the past 10 years resulting in significant improvement in productivity in terms of production rates and duration. In a recent field study1 involving more than 100 well stimulations, these SMAs were found to dramatically enhance the recovery of aqueous-based fracturing fluids during well cleanup following the fracturing treatments. This paper describes how a simple modification to proppant surfaces resulted in these dramatic post-frac well cleanups and subsequent well productivity. A comparison of laboratory results along with actual case histories will help explain the significant improvement in hydrocarbon production observed in fracture stimulated wells using SMA-coated proppant. Introduction More than 10 years ago, the concept of coating proppant with a surface modification agent (SMA) to stabilize the proppant pack and formation/proppant pack interface was introduced. Since that time, widespread use of this technology to sustain fracture conductivity has demonstrated excellent results. Numerous papers2–5 have described the mechanism by which SMA materials function to provide sustained conductivity, and in some cases, enhanced conductivity. Initially, the SMA material was described as a "nonhardening resin manufactured from renewable resources."3 A particularly useful SMA was made6 from "tall oil," a byproduct of the paper and pulp industry; this SMA combined surface activity with a polymeric material. The polymer is insoluble in both water and oil, but is soluble in a few highly oxygenated solvents, which makes it particularly suited for treating proppant. It is described as thermally stable, with a polar polyamide backbone with long, pendent fatty chains. The polar polyamide portion of the polymer tends to adsorb strongly on mineral surfaces while the hydrophobic fatty chains tend to extend away from the mineral surface. This leaves the mineral surface highly hydrophobic, hydrophobic and sticky to the touch. The SMA coating on proppant changes the interaction of the proppant with its surroundings in several ways. The first is to cause the surfaces to become tacky, causing a significant decrease in the tendency of proppant to flow out of a fracture. It has been reported7 that even with fracture closure, there is a significant tendency for proppant to flow back, and that this tendency increases with closure stress. In fact, the application of SMA has been shown2 to increase the critical fluid flow rate required to initiate proppant flowback by 3 to 5 times that of uncoated proppant. Proppant pack stability is important in many cases. High stress, coupled with stress cycling, can lead to proppant crushing, and subsequent migration of fines formed by proppant crushing and bridging off, eventually plugging the pack's permeability. The tendency for crushed proppant fines to migrate is mitigated by the application of SMA to the surface of proppant as it is used in the fracture treatment. The same application of SMA to proppant can also be utilized to prevent formation fines from migrating into the proppant pack, thereby conserving the effective fracture width. This application has found widespread use in poorly consolidated formations completed using frac-pack completions. In these applications, greater than normal fracture conductivity can be achieved by using a proppant size larger than normally recommended to prevent formation fines invasion as the SMA-coated proppant traps the formation fines at the formation/fracture pack interface.3 Application of SMA-coated proppant in coalbed methane producers was found to provide long-term coal fines control.8 Without SMA, typical fracture stimulation treatments in these applications required frequent refracturing. In the SMA treatment's ability to affect fracture sustainability, it was observed that the load recovery from the frac treatment, and the dewatering process, were both significantly accelerated. Coating SMA onto off-spec, small-sized proppants for use in water fracture stimulation treatments has in some areas delivered acceptable conductivity, even with these poorer grades of proppant. It was further observed that significantly improved fracture fluid recovery was obtained during these treatments. This paper presents field and lab data demonstrating that coating proppant with SMA can impact fracture fluid recovery and suggests some possible mechanisms to support these observations.
Abstract A new ultrasonic leak detection logging tool conveyed on electric line, and recently on wireline in memory mode, has been introduced which can detect leaks as small as 1/2 cup per minute. This revolutionary tool has been used to accurately identify leaks in tubing and behind pipe. Wells that otherwise would immediately be slated for a rig workover (RWO) have been repaired with non-rig solutions. Ultrasound energy has very rapid attenuation and the ability to transmit through various media and behind pipe. These attributes allow pinpoint accuracy for leaks as small as 0.0024 gallons per minute (gpm). The tool incorporates data acquisition equipment and filtering algorithms which allow continuous logging. The technology is far superior to old-style noise logs which require time consuming stationary counts. To date, BP has run 21 ultrasonic leak detection logs in Alaska fields with an 81% success rate. The recent ability of this tool to be conveyed in memory mode has opened up additional logging opportunities. This has led to the development of a new technique using nitrogen to identify wells that leak only to gas. Application of this tool has great significance for any operator concerned with well integrity, and particularly, in areas where rig workovers are expensive including remote, offshore, and arctic locations. Introduction BP operates several enhanced oil recovery and waterflood oil field which have experienced well integrity issues as the field matures. Non-rig tubing repairs have become a viable alternative to RWO's, which can easily exceed 1 million dollars. Repair methods include tubing straddles and coiled tubing packer repairs. The advantage over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster. However, the main limitation for non-rig candidate selection has been in identifying leaks which are below the resolution of conventional leak detection methods. Often a well with annular communication had to be worked over because the leak point could not be determined. The ultrasonic leak detection tool has provided a step change in leak identification. Prior to its introduction, it was virtually impossible to detect leaks smaller than 1 gpm. Often the velocity and temperature changes associated with these leaks are below the resolution of conventional logging tools, including spinners, temperature logs, down-hole cameras, and noise logs. These tools are even more limited when trying to detect leaks that occur behind tubing. The ultrasonic leak detection tool can identify leaks so small as to be almost unbelievable. Tool Principles and Operation. SPE paper 102815 details the tool physics and development history of the ultrasonic leak detection log. Tool principles are briefly summarized here. The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. The ultrasonic logging tool (Figure 1) utilizes a sensor that detects a frequency spectrum, including those typically produced by leaks. The signal is processed by a series of band-pass algorithms that focus on frequencies in the ultrasonic range. Virtually all audible noise associated with tool movement is filtered out, allowing continuous logging. Typical logging speed is 30 feet per minute (fpm) and leaks can be identified while logging in either an up or down direction. Greater accuracy is achievable due to the characteristics of ultrasound, which attenuates, or dies away, quickly in fluids. Ultrasound typically travels only 3–10 ft in a wellbore before attenuating. This attenuation results in a very sharp leak character, typically identifying the leak within 1 to 2 feet.
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Abstract Horizontal well technology has been widely used in developing gas fields. Very commonly, these wells are hydraulically fractured to improve productivity in low permeability reservoirs. A previously developed method, the Distributed Volumetric Source method (DVS), was applied to horizontal gas wells with or without fractures to predict well performance. The method is flexible and can be easily applied. The method provides an effective tool to evaluate horizontal well design and well stimulation design for gas wells. In this paper, we conducted a well performance study by applying the DVS method to typical gas formations in East Texas Basin, San Juan Basin, and Appalachian Basin.. The objective is to determine the best practice to produce from horizontal gas wells. With the transient flow feature of the DVS method, well placement for multiple horizontal wells in a defined drainage area can be studied, and the limit of well spacing and wellbore length is identified. For fractured wells, well performance of a single fracture and multiple fractures are compared, and the effect of the number of fractures on productivity of the well is presented. Realizing that reservoir permeability and anisotropy ratio are the critical parameters in developing low-permeability gas fields, the effect of permeability on well performance, well placement and fracture treatment design is addressed in the paper. Introduction Development of low permeability tight gas reservoirs is becoming attractive to the energy supply problem we are facing today. The lack of flow path for gas is the biggest limitation for tight gas formations. In order to overcome that limitation, horizontal wells have been drilled, and many of them were furthermore fractured to expand the contact between the well and the formation. To study the effects of reservoir properties, well structures, and fracture treatment design, on well performance in tight gas formations, we need a simple but robust method to predict the performance of horizontal wells, with or without fractures. Horizontal well models have been presented in many literatures in the past. In order to arrive at an analytical solution, different boundary conditions have to be assumed. Thus, the models have been divided to steady-state models (Butler 2000, Furui et al 2003, and Zhu 2006) pseudo-steady state models (Babu and Odeh, 1988 and 1989), and transient flow models (Goode and Thambynayagam, 1987, Ozkan 1988 and 1989). For low permeability formations, transient flow period for a horizontal well may be significantly longer than for conventional formations. A model that can handle both transient and pseudo-steady state flow conditions will be convenient. A previous study presented a Distributed Volume Source method (Valko and Amini, 2007). The method solves the flow problem in a box-shaped reservoir with a box-shaped volumetric source. The shape of the sources is flexible, easily portraying a horizontal well with or without fractures. A smooth transition between transient and pseudo steady state flow regions was achieved by the method. The main concept of the method was to find the analytical solution for the response of a closed rectilinear system to an instantaneous volumetric source. This solution is then integrated over the time to provide the response for a continuous volumetric source. Application of the principle of superposition was used to simulate multiple fractures along a horizontal well. The method is developed for a source with uniform flux over its volume. The extension of method to cases with infinite conductivity is made possible by dividing the source into segments of uniform-flux sources. The Distributed Volumetric Source (DVS) method was extended to gas wells (Zhu et. al, 2007), and that will be the approach used in this study. Application of DVS method to Case Studies In this paper, we apply the DVS method to several typical tight gas fields in the US in different basins to study the effect of designing horizontal wells and fracture treatments on well performance. Fig. 1 shows all the tight gas basins in the USA. This paper uses data from East Texas Basin, San Juan Basin, and Appalachian Basin. It is important to point out that all of these basins have their unique characteristics, and the results and conclusions made from the study are based on each individual basin, and may not be used as general conclusion.
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- (23 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling technologies have pioneered these advancements, with current technology capable of drilling thousands of feet through a thinly bedded hydrocarbon reservoir. Completion advancements designed for extended horizontal wellbores have also advanced, albeit at a slower pace. Initially horizontal drilling was limited to naturally fractured reservoirs with simple open hole or slotted liner completions. This was due primarily to the ability of the reservoir to flow economically without the need for stimulation. Reservoirs requiring stimulation were initially not candidates for horizontal drilling. Developments in completion technology specific for horizontal wells have broadened the reservoirs where horizontal wells can be effectively stimulated. When drilling a horizontal well, there are two completion options. First, the horizontal can be completed open hole, or with slotted/perforated liner. Effective stimulation along the horizontal wellbore is impossible. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig up and down of the stimulation equipment are required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit. This paper will discuss a new open hole completion system run as part of the production liner, does not require cementing and provides mechanical diversion at specified intervals, thus allowing fracturing and stimulations to be effectively pumped to their targeted zone. Details of the engineering design and testing will be specified, with elaboration on the applications and case histories were these systems have been successfully deployed. The case histories will detail the operational efficiencies of the system in conjunction with the enhanced production realized. Introduction While horizontal drilling has progressed over the last decade to become the field development method of choice in many cases, there have been certain limiting technologies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture different intervals of the horizontal wellbore, particularly in reservoirs that were not naturally fractured. The use of limited entry and bullheading techniques provided little if any benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix, heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation methods employed and their shortcomings in horizontal applications. Thus, the additional economics required to drill a horizontal well was not justified by the equal to or slightly better production results compared to vertical wells. Horizontal completions where the wellbore is cased and cemented, effective stimulation techniques were addressed some years back by limited entry techniques and then later by the use of composite bridge plugs set on coiled tubing (CT), followed by perforating and then stimulating the well. The bridge plug provides the mechanical diversion in the liner to effectively stimulate each selected zone. This process is then repeated for the number of stimulations desired for the horizontal wellbore. After all the stages have been completed, CT is used to drill out the composite bridge plugs and establish access along the horizontal.1 Although effective, the inherent cost of multiple interventions with CT, perforating guns and deployment of fracturing equipment needed for each stage are extremely high, not to mention very inefficient and time consuming. This coupled with the associated mechanical risks often does not allow for the optimum number of fractures to be placed along a given horizontal interval. Production using this method can also be limiting, as cementing the wellbore closes many of the natural fractures and fissures that would otherwise contribute to overall production.
- Geology > Rock Type > Sedimentary Rock (0.70)
- Geology > Geological Subdiscipline (0.48)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Completion Installation and Operations (1.00)
Abstract Horizontal and multilateral completions are a proven, superior development option compared to conventional solutions in many reservoir situations. However, they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion "hot-spots" and plugging of screens is another challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early '90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques. An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well's inflow profile and minimize the annular flow at the cost of a limited, extra pressure drop. Fractured and more heterogeneous formations require, in addition, the installation of annular isolation. The new technologies of Swell Packers and Constrictors can provide this annular isolation in an operationally simple manner. This paper describes the history of ICD development with an emphasis on the designs available and their areas of application. These technical criteria will be illustrated using published field examples. The ICD's flexibility will be shown by its integration with other conventional and advanced production technologies e.g. Stand-Alone-Screens, annular isolation, artificial lift, gravel packs and intelligent completions in both horizontal and multilateral wells. It will be shown how the value of such well-construction options can be quantified using commercially available, modelling simulators. Simple, but reliable, guidelines on how to model the performance of ICDs over the well's life will be provided. This technique can thus be used as part of the value quantification process for both the evaluation of completion options and for their detailed design. 1 Introduction Horizontal and multilateral wells are becoming a basic well architecture in current field developments. Advances in drilling technology during the past 20 years facilitated the drilling and completion of long (extended reach) horizontal and multilateral wells with the primary objective of maximising the reservoir contact. The increase in reservoir exposure through the extension of well length helped lower the pressure drawdown required to achieve the same rate and enhance the well productivity 1–2. Major operators have proved the advantages of such wells in improving recovery and lowering the cost per unit length. The production from thin oil column reservoirs (e.g. The Norwegian Troll Field) became a reality thanks to such wells 3–4. However, the increase in wellbore length and exposure to different reservoir facies came at a cost. Frictional pressure drop caused by fluid flow in horizontal sections resulted in higher drawdown-pressure in the heel section of the completion, causing an unbalanced fluid influx. Hence, coning of water and gas toward the heel of the well was observed. Variable distribution of permeability along the wellbore also results in variation of the fluid influx along the completion and an uneven sweep of the reservoir. Annular flow is another challenge often encountered when horizontal wellbores are completed with Stand-Alone-Screens (SAS) or with pre-perforated/Slotted liners. Neither of these completion options employs any form of isolation between the casing and the formation (i.e. external casing packers). Annular flow, which is dependent on many parameters such as the size of the clearance between the sandface and the liner (screen) outer diameter, still imposes several problems including: dislodging of the sand grains causing erosion of the sandface, formation of "hot-spots" and plugging of the sand screens 5–6. Previously, the elimination of such phenomenon required the utilization of gravel packs or installation of Expandable Sand Screens (ESS), which often had a significant impact on the well productivity and/or involved a very complex operation 6–7.
- Asia > Middle East > Saudi Arabia (0.68)
- Europe > Norway > North Sea > Northern North Sea (0.34)
- North America > United States > Texas > Harris County > Houston (0.28)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (22 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics (1.00)
Application of Dipole Sonic to evaluate Hydraulic Fracturing
Tellez, Oscar Mauricio (Hocol S.A.) | Casadiego, Armando (Halliburton) | Castellanos, Julian Enrique (Halliburton Energy Services Group) | Lopez, Emiliano Rodrigo (Halliburton Wireline Services) | Sorenson, Federico (Halliburton Co.) | Kessler, Calvin W. (Halliburton Energy Services Group) | Torne, Juan Pablo (Halliburton)
Abstract Hydraulic fractures are used worldwide to enhance oil and gas production. In many cases, the stimulation jobs cover multiple intervals and the evaluation of the individual zones is not a straightforward process. In Colombia (Figure 1), it was proposed to HOCOL to run the crossed dipole sonic, inside casing before and after a hydraulic fracturing job, to evaluate changes in anisotropy due to the treatment. This paper presents the complete process, including the planning and evaluation of the logging and hydraulic fracturing, and the use of this technique to evaluate hydraulic fracturing effectiveness when multiple zones are open and fractured simultaneously. The planning process includes the use of the dipole sonic to determine rock properties and the calibration process to adjust the computation of sanding potential and fracturing pressures. The use of acoustic anisotropy in cased hole proved to be an effective method for evaluating the effectiveness of the fracture treatment and for defining the characteristics of the resulting fractures. This is an innovative technique; a second application well is presented in this paper including the results. Introduction The evaluation of hydraulic fracture height has been performed by using several traditional methodologies,1-3 such as temperature logs and radioactive tracers (Figure 2). The main disadvantage of the use of temperature logs is the limited vertical resolution. The method can be improved when combined with radioactive tracers (Figure 3). A qualitative relationship has also been observed between the level of radiation and the fracture width 4-6 (Figure 4). The simultaneous use of fullwave sonic, spectral gamma ray, and temperature logs have also been investigated and documented 7. This technique showed the advantage of determining a continuous profile for the dynamic mechanical properties and the effect of the hydraulic fracture stimulation on the acoustic waveforms. The absence of shear wave information limited the use of the technique (Figure 5). The introduction of dipole sonic logging and, more recently, the crossed dipole has helped to enhance the previous method to determine the vertical extension or height of the hydraulic fracture. Vertical extension mapping is important when there is a possibility to communicate water zones or when multilayer fractures are attempted. The use of compressional and shear information to determine dynamic mechanical properties is fundamental to effective job design and to prediction of the performance of the fracture. The use of shear wave anisotropy is important in the computing of an accurate fracture height and in evaluating the efficiency of the fracture.8 Another technique recently introduced is the microseismic technology.9-10 Microseismic wavelet mapping is based on real-time monitoring, using high-resolution geophones to monitor the development and downhole shape of the fracture (Figure 6). The use of the WaveSonic® Hydraulic Fracture Height Evaluation Technique, when combined with the microseismic technology, adds value to the evaluation and planning of production enhancement. In this paper, well P-7 was fractured commingled because there is normally a significant improvement in production after the hydraulic fracture. The fracture is performed to improve communication of the reservoir to the wellbore,11 but the evaluation of individual sands is an issue when multizones are fractured together. Based on the conventional openhole logs and field experience, there were doubts about the even distribution of the sand along the different intervals open for production. In another case presented in this paper, well V-1 was fractured zone by zone and the evaluation of the fracture height was performed by using the same technique for the different fractures. The evaluation of the performance after the job was also completed using a matching technique with simulator FracproPT®, based on downhole pressure measurements taken during the job. This paper will discuss the theory behind the WaveSonic® Hydraulic Fracture Evaluation Technique, as well the operational procedures and results of this application for a particular well.
- South America > Colombia (0.70)
- North America > United States > Colorado (0.28)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Colombia > Caballos Formation (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Brushy Canyon Formation (0.99)
- (9 more...)
Geomechanical Applications For Near Balance and Dynamic Underbalanced Perforating Technique In Over Pressured Gas Zones in Burgos Basin
Campos, Humberto (Petroleos Mexicanos) | Martinez Alanis, Sergio (Halliburton) | Pizarro, Hugo (Halliburton) | Kessler, Calvin W. (Halliburton Energy Services Group) | Torne, Juan Pablo (Halliburton)
Abstract Electric, acoustic, and nuclear logs, as well as rock properties information from cores and downhole tests, such as leakoff, minifrac, hydraulic fracturing, and pressure buildup, are normally available in the gas fields in Northern Mexico. The existing information was used to fully determine rock properties and to select the optimum perforating technique to minimize formation damage and to help produce gas from this type of reservoir. The critical drawdown and formation compressibility were evaluated based on the integration of rock mechanical properties from dipole sonic and from density logs with core analysis information determining proper dynamic-to-static calibration parameters. The process to design the perforating technique to maintain a balance between hole diameter for future hydraulic fracturing and maximum penetration to reduce the skin damage in this type of reservoir is presented in the paper. The results from different wells, as well as the advantages and disadvantages of the technique, are compared. Introduction The main objective of the perforating process is to establish communication to the reservoir to be able to have production efficiently and effectively. This process is particularly important in the low permeability, overpressured tight gas formations even so it is apparently simple because most of the formations require hydraulic fracture for commercial production. In fact, it has been a challenge when selecting the perforating technique to maintain a balance between charge penetration, hole size, and reservoir pressure for some well completions. If the perforating technique is not optimized for the particular reservoir, the results of the initial flow test, fracture extension, and well production are, in most of the cases, more expensive and less efficient. In the case of overpressured tight gas reservoirs, the application of geomechanical models and field experience has shown that the best technique is nearbalance perforating. The same applies for high porosity and permeability reservoirs where there is tendency to have sand production if extreme underbalance techniques are used. In the case of fractured or anisotropic reservoirs, the best technique is nearbalance oriented perforating. Well Perforating and Recent Developments Well perforating began over 70 years ago with the development of various systems to establish communication between the cased wellbore with the formation. The objective of any system is to achieve the maximum flow efficiency for the particular reservoir while keeping the skin damage to a minimum. One of the first systems was bullet perforating, which was conceived and patented in 1926. This system had some drawbacks because the bullet remained in the perforation tunnel and penetration was poor but, on the contrary, the flowing efficiency was relatively good because the perforation tunnel with the shape of a near uniform cylinder. In January 1945, Ramsey C. Armstrong founded Well Explosives Company (Welex) and, in 1946, the shaped charge was introduced into the oil industry. The principle of shaped charge perforating was developed in WWII for armor piercing shells used in bazookas to destroy tanks. This new technology allowed the oil producers to have some control over the perforation design (penetration and hole size) to optimize productivity. When compared to the bullet system, the shaped charge perforation tunnel is a conic cylinder and the liner debris is either dispersed through the entire tunnel or flowed back into the well.1-2 In general, it was observed that the wells perforated using the jet perforator system had higher flow rates than the wells perforated using the bullet perforator system because the penetration of the first system was larger than the other system.3 A shaped charge is basically composed of the charge case, liner, main explosive, and the secondary explosive. The jet perforating system includes the shaped charges, detonating cord or primacord, and the electric or pressure detonator (Figure 1). In general, the angle of the liner's cone controls the penetration and the entry hole size, as well as the explosive power.4-5
- North America > Mexico > Tamaulipas (0.41)
- North America > Mexico > Nuevo León (0.41)
- North America > Mexico > Coahuila (0.41)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- (3 more...)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract Rapid production decline rate is associated with the loss of fracture conductivity after hydraulic fracture stimulation. This loss of conductivity has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Surface modification agents were introduced in the stimulation market around 1997, and according to literature published since then, these materials have been helping to sustain fracture conductivity, and subsequently, mitigating production decline rates. This paper presents long-term results from the use of these materials in hydraulic fracture stimulation operations in the Burgos Basin in northern Mexico; results from offset wells are also presented for correlation and comparison. Production from this basin comes from low-permeability sandstones normally considered tight gas formations. Introduction Burgos Basin is located in northeastern Mexico along the southern border of the U.S. This gas basin covers more than 50,000 km2 (Fig. 1) and accounts for one third of the reserves of nonassociated gas in the country. The gas fields are located along well-defined bands that extend across the shared border between Mexico and the U.S. They are complex, sandy reservoirs, higly compartmentalized, and made up of a great number of small independent blocks characterized by very low permeability. Sustaining a high production level in this area requires a large number of wells to be drilled and hydraulically fractured.1 Burgos Basin gas production started in the mid-Forties; however, its complex characteristics caused a rapid decline by the early Nineties. In 1994, a second phase began when an intensive drilling program for exploration and development was kicked off with the goal of increasing gas production. New reserves were added by improving drilling and completion methods, identifying bypassed pay, identifying field extensions from 3D seismic information, and making new exploration discoveries. Fig. 1—Burgos Basin location in northern Mexico. Factors Affecting Fracture Conductivity Several factors affect the conductivity of a propped fracture and ultimately the productivity of a well. As mentioned, the migration of fines onto the proppant pack after a hydraulic treatment has been recognized as one of the main factors affecting fracture conductivity. This occurs when flocculation of the fines creates larger particles that result in a pack plugging. Infiltration of fines into a pack in effect reduces the conductive width of the fracture and provides a source of fines that may migrate upon stress cycling. Fines can be a product of the proppant breakdown under closure stress or they can come from the formation that is in contact with the proppant bed. Fines migration is often related to unconsolidated formations; however, it can also come from hard rocks if the fracture face crushes under the load of the proppant.2
- North America > Mexico > Tamaulipas (0.96)
- North America > Mexico > Nuevo León (0.86)
- North America > Mexico > Coahuila (0.86)
- North America > United States > Texas > Vicksburg Formation (0.99)
- North America > Mexico > Tamaulipas > Burgos Basin > Cuitlahuac Field (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- (2 more...)
Abstract Fracture spacing is an important concept for characterizing flow properties of naturally fractured reservoirs, since the main function of fractures that separate matrix blocks is transporting fluids through long distances; however, the estimation of fracture spacing presents some difficulties mainly due to the fact that fractures occur at different scales, going from microfractures in thin sections and minifractures in cores, up to macrofractures in geological outcrops. The scale of interest in this work is that used in reservoir simulation, which is of the order of feet or meters. This article is based on the ideas developed in a previous paper, where a procedure to locate fractures is presented. That procedure, which makes use of resistivity data obtained through well logging, visualizes the fractures as highly conducting channels within a low conductivity medium (the rock matrix). By using a special way of data processing, it is possible to filter out data that are not associated with fractures, keeping only those data related to fractures. In this way, fracture spacing can easily be estimated. However, that procedure exhibits some uncertainties which must be overcome to make it a more reliable one. In this work, a study is made to search for an improved procedure to estimate fracture spacing. For this purpose, fractures are considered at two scales: local scale which includes micro- and minifractures present in matrix blocks, and at reservoir scale which refers to fractures separating matrix blocks. These latter fractures, called principal fractures, constitute the main fracture network, and are the subject matter of this work. Conductivity studies reveal that local scale fractures have a frequency distribution quite different from that of principal fractures. As it will be seen below, this fact facilitates establishing a procedure for estimating fracture spacing without uncertainties. To make the ideas clear, an application to a carbonate reservoir is presented. The results obtained show that the improved procedure is a simple, reliable, and practical tool for establishing the distribution of fractures along a well, from which fracture spacing can be inferred. Introduction Non sealed fractures in naturally fractured reservoirs are high conductivity channels; hence, fracture spacing is a factor that controls, to a great extent, the flow properties of such systems. In spite of its importance in areas such as hydrology, geology, geophysics, and petroleum engineering, the problem of estimating fracture spacing has not received the proper attention from researchers, and the specialized literature presents relatively few works treating in depth this theme. Among the currently used techniques for detecting fractures are well testing, core analysis, direct outcrop observation, and well logging.1–4 In this work, an improved way to determine fracture spacing is approached. In a previous paper,5 a procedure for estimating fracture spacing was developed. That procedure is based on data analysis of formation resistivity factor obtained through well logging. The fundamental consideration of the procedure is that fractures are high conductivity anomalies in a low conductivity medium (the matrix) and, consequently, the basic tool for studying fracture spacing is based on the detection of contrasts in electrical conductivity. To this end, a special analyzing process is used to distinguish between data associated with fractures and non-associated. However, such a procedure does not allow establishing with certainty a discriminating threshold between both types of data. The fractures referred to in this work are those surrounding matrix blocks. These fractures, called principal fractures, constitute the main fracture network, which has the property of transporting reservoir fluids through long distances, and eventually to the producing wells, in opposition to micro- and minifractures which act at block scale, and whose main function is to convey fluids within the matrix blocks and towards the principal fractures.
- North America > Mexico (0.29)
- North America > United States (0.29)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)