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Abstract Fracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments. A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells. The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.
Gurmen, M. Nihat (Schlumberger) | Fredd, Christopher N. (Schlumberger) | Batmaz, Taner (Schlumberger) | Kurniadi, Stevanus dwi (Schlumberger) | Zeidi, Omar Al (Schlumberger) | Kanneganti, Kousic (Schlumberger) | Nasreldin, Gaisoni (Schlumberger) | Khan, Safdar (Schlumberger) | Tineo, Roberto (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
Abstract Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges. Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments. Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments. This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.
Summary The Sacatosa field in west Texas was discovered in 1956. Since then, more than 1,500 wells have been drilled and completed in the main reservoir section known as the San Miguel 1. The San Miguel 1 is primarily low-permeability sandstone, with several shale layers dispersed throughout. Economic development of the field requires effective well stimulation and an active waterflood program to provide pressure maintenance. Unfortunately, the available injection water is of poor quality and can rapidly plug up pore throats with solids, resulting in significant near-wellbore formation damage. When these factors are considered, hydraulic fracturing of both injector and producer wells is a viable option for improved long-term well performance. However, because of relatively shallow depths, traditional hydraulic-fracturing practices can lead to a multiplane fracture system with a mix of horizontal and vertical components. A significant presence of horizontal fractures can be detrimental to fractured-well performance because of the low conductivities of the fractures. In producer wells, this could impair production if the reservoir is laminated and has low vertical permeability. In injectors, water-front movement and sweep efficiency would be diminished greatly. This paper discusses the steps taken to plan and develop a strategy to place vertical fractures in shallow San Miguel 1 sands. These findings can easily be extended to similar shallow-depth reservoirs worldwide. Some major modifications in completion design included changes in perforation strategy, redesign of the pump schedule, and implementation of a staged stimulation. Fracturing treatments were pumped on a total of 26 injectors and eight producers through a variety of methods, including coiled-tubing fracturing. Post-fracture analysis suggests a strong vertical-fracture component, and analysis of injectivity tests shows fracture parameters in line with design objectives. All the producers that were fracture stimulated with this technique reported higher initial production when compared with wells stimulated through the use of legacy treatment schedules.
Abstract The Sacatosa Field in West Texas was discovered in 1956. Since then over 1500 wells have been drilled and completed in the main reservoir section known as the San Miguel 1. The San Miguel 1 is primarily a low permeability sandstone, with several shale layers dispersed throughout. Economic development of the field requires effective well stimulation and an active waterflood program to provide pressure maintenance. Unfortunately, the available injection water is of poor quality and can rapidly plug up pore throats with solids, resulting in significant near wellbore formation damage. When these factors are considered, hydraulic fracturing of both injector and producer wells is a viable option for improved long-term well performance. However, because of relatively shallow depths, traditional hydraulic fracturing practices can lead to a multiplane fracture system with a mix of horizontal and vertical components. A significant presence of horizontal fractures can be detrimental to fractured well performance because of their low fracture conductivities. In producer wells, this could impair production if the reservoir is laminated and has low vertical permeability. In injectors, water front movement and sweep efficiency would be greatly diminished. This paper discusses the steps taken to plan and develop a strategy to place vertical fractures in shallow San Miguel 1 sands. These findings can easily be extended to similar shallow depth reservoirs worldwide. Some major modifications in completion design included changes in perforation strategy, redesign of the pump schedule and implementation of a staged stimulation. Fracturing treatments were pumped on a total of 26 injectors and 8 producers using a variety of methods, including Coiled Tubing fracturing. Post-fracture analysis suggests a strong vertical fracture component and analysis of injectivity tests shows fracture parameters in line with design objectives. At least a two-fold increase in production was observed in producers that were fracture stimulated using these techniques.
Sayyafzadeh, M.. (Petroleum Engineering Department, Amirkabir University of Technology) | Pourafshary, P.. (Institute of Petroleum Engineering, University of Tehran) | Rashidi, F.. (Chemical Engineering Department, Amirkabir University of Technology, Tehran, Iran)
Abstract Developing a giant field is a challenging task; the main goal is to reach to the highest ultimate oil recovery (UOR) by finding the best locations for new producers and injectors. Besides, converting existing producers to injectors and vice versa are other ways to increase the recovery. Hence, in this approach, we use combination of infill drilling and converting producer well to injector so as to maximize UOR. Lots of methods are recommended to develop fields, but none of them is comprehensive enough. To develop a field, the location of a new well should be considered and then its effect on the ultimate production should be investigated. This approach normally deals with testing hundreds or thousands of potential infill alternatives by numerical simulations which is a very time consuming and expensive process. One of the newest methods to develop a field is using streamline simulation. In this approach, we suggest two main stages; first to gain the most possible advantages from the infill drilling, new producers should be drilled in sections of the reservoir where the streamline density is low and the oil saturation is high. Second, converting mostly dead producers to injectors could be a very useful method based on the density of the streamlines around the old producers. We used the method to develop a complicated reservoir. For this reason, we used grid-base and streamline simulation to verify the outcomes. The results show that UOR increases around 70 percent by infilling and switching the producers to injectors. In this work, we use the streamline approach to develop a guideline to drill new producers and switch some of the old producer wells to injectors in order to increase the oil recovery. This method could compete favorably with EOR processes on a recovery basis for much less investment and operating cost.
Copyright 2010, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans, Louisiana, USA, 2-4 February 2010. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright. Abstract A significant performance and cost improvement was achieved with the application of hybrid Coiled Tubing (CT) drilling equipment and techniques on the Chittim Ranch in Maverick county Texas. During this drilling program, 233 wells were grass-root drilled using the hybrid CT unit. Coiled tubing drilling equipment and techniques reduced the average time to complete a well by 60% when compared to conventional rotary rig drilling. This increase in drilling performance coupled with a turnkey contract resulted in a 14% (33% adjusted for inflation) cost reduction per well when compared to the most recent conventional drilling data from this area. This paper will review the process used in choosing a CT solution, the hurdles overcome, the problems encountered, and the lessons learned in managing and operating this CT Drilling (CTD) campaign. The paper will also provide an overview of CT coring performed in one of the wells during the CTD campaign.
Two sets of west Texas carbonate reservoir and waterflood data were studied to evaluate the impact of infill drilling on waterflood recovery. Results showed that infill drilling enhanced the current and projected waterflood recovery from most of the reservoirs. The estimated ultimate and incremental infill drilling waterflood recovery was correlated with well spacing and other reservoir and process parameters. Results of the correlation indicated that reducing well spacing from 40 to 20 acres [16 to 8 ha] per well would increase the oil recovery by 8 to 90% of the original oil in place (OOIP). Because of the limited data base and regressional nature of the correlation models, the infill-drilling recovery estimate must be used with caution.
The concept of optimal well spacing for oil recovery has been am important and controversial subject for more than 50 years. Before 1960, ultimate recovery by primary mechanisms was considered to be independent of well spacing. In 1969, Davis and Shepler reported that by reducing well spacing from 40 to 20 acres [16 to 8 ha], primary oil recovery from the San Miguel Unit of the Sacatosa field in southwest Texas was increased by at least 14% OOIP. The relationship between primary ultimate recovery and well spacing was not well established, possibly because reservoir heterogeneity was not considered. Waterflood technology began developing in the early 1920's and became popular in the 1950's. Mainly for economic reasons, the use of existing wells with some additional infill wells was common for waterflood projects, but the impact of well spacing on optimal waterflood recovery was not seriously considered. In 1971, Emmett et al reported that reducing well spacing from 40 to 20 acres [16 to 8 ha] economically accelerated the producing rate and increased ultimate recovery by gas/water injection in Wyoming's Tensleep reservoir. In 1973, Thomas and Driscoll reported that infill drilling in chickenwire patterns in the Slaughter field, TX, increased oil recovery by an average of 3.6% OOIP and was profitable. Infill drilling for improving waterflood recovery was initiated in the early 1970's in the carbonate reservoirs in the Permian Basin of west Texas. Results in the literature indicated that infill drilling can improve ultimate recovery from heterogeneous reservoirs; however, a consistent set of field data was not available for developing a correlation between waterflood recovery and well spacing. The objective of this study was to acquire a set of consistently evaluated field data from west Texas carbonate reservoirs to determine the impact of infill drilling on waterflood recovery and to develop linear regression models correlating waterflood recovery with respect to well spacing and other reservoir/process parameters.
Effect of Well Spacing on Waterflood Recovery
Reservoirs Studied. For this Phase 1 study, 24 reservoirs were selected from Railroad Commission of Texas Bulletin 82. The purpose of this study was to use a publicly available data base to evaluate statistically the effect of well spacing on waterflood recovery. Table 1 lists the reservoir units and properties. Reservoirs developed on a five-spot pattern only were selected, to avoid the effect of different flood patterns on oil recovery efficiency and on the correlation. In this study, the well spacing was of primary concern; the effect of infill drilling on incremental recovery was not considered. The reservoir and process data were obtained mainly from Bulletin 82. The data were adjusted and updated with additional data gathered from Railroad Commission of Texas dockets and from the literature. The reservoirs studied are located in the region on the north end of the central basin platform and Midland basin and south of the Matador Arch, as shown in Fig. 1. The pays of these reservoirs are in the lower part of the San Andres formation. The lithology is composed of dolomite, anhydrite, siltstone, and salts. The depositional sequences are cyclic in nature. The component facies of each cycle are thin and laterally discontinuous. The heterogeneity of the reservoir rocks and the discontinuity of the pay Sections are very favorable for infill-drilling operations to improve waterflood recovery.
Correlation of Waterflood Recovery With Well Spacing. Table 2 shows the oil recovery and the well spacing of the 24 units studied. A series of least-squares fittings was made to correlate waterflood recovery with each reservoir and process parameter, which included productive area, net pay, porosity, permeability, gravity, flow capacity, and well spacing. Results showed that the correlation with all parameters except well spacings was very poor. The waterflood recovery showed a correlation trend with well spacing. Two correlation equations were developed with a least-squares fitting program.
Paraffin and scale deposition in wells at Conoco's Paraffin and scale deposition in wells at Conoco's Chittim lease has consistently hampered operations. Numerous chemicals were laboratory and field tested to determine the two most cost-effective chemicals for paraffin and scale treatment. These were a paraffin solvent and a sulfamic acid system, paraffin solvent and a sulfamic acid system, respectively. Gross lease revenue has increased substantially with the use of the two chemicals in a fieldwide treatment program.
Conoco Inc. operates a shallow waterflood on the N. J. Chittim lease, Sacatosa Field, Maverick County, Texas, which consists of 628 producing wells and 580 injection wells. Current field production is approximately 3700 BOPD. Unfortunately, scale and paraffin deposition in these wells has consistently caused operating problems: 1) plugged perforations, pumps, and problems: 1) plugged perforations, pumps, and flowlines, 2) frequent well pulling, and 3) reduced mechanical oil/water separation. A study was undertaken in 1983 to determine the most cost-effective chemicals and treatment procedures that could be applied on a fieldwide basis to minimize operating problems due to paraffin and scale. Extensive laboratory and field paraffin and scale. Extensive laboratory and field testing of seven chemicals indicated a paraffin solvent and a sulfamic acid to be most cost-effective. Consequently, a continuous chemical treatment program was implemented utilizing these two chemicals.
SELECTION OF TEST CHEMICALS
Paraffin Chemicals Paraffin Chemicals Five major chemical companies were provided with a sample of Chittim paraffin collected from pulled tubing. Each chemical company's sales representative was asked to determine the most effective solvent they could offer to treat the paraffin. Each vendor then supplied a sample of the recommended solvent.
A Paraffin Flask Test was used to compare the efectiveness of the five different solvents as folows:
Lease water (100 mls) was placed into each of six clean bottles. A four gram ball of Chittim paraffin was then placed in each bottle. Next, 0.5 ml of the recommended paraffin solvent was placed in five of the paraffin solvent was placed in five of the bottles. Chemical was not added to the sixth bottle which served as a blank. All bottles were then placed into a hot water bath, approximately 190 degrees F, until all of the paraffin melted. The samples were then paraffin melted. The samples were then removed from the hot water bath and agitated simultaneously until the paraffin resolidified (approximately 10 minutes).
Effectiveness of the five chemicals was visually judged according to the following checklist:
1) Size and shape of resolidified paraffin particles - an effective paraffin solvent yields small (1-2 mm diameter) balls floating on the surface of the water that resemble coffee grounds. The tiny, non-adhering balls indicate that the solvent has good dispersing characteristics and will prevent the paraffin from reagglomerating.
2) Paraffin adhering to bottle - paraffin adhering to the test bottle or cap indicates that the chemical is not totally effective in preventing paraffin redeposition. Consequently, the more paraffin remaining on the sides of the bottle, the less effective the chemical is in limiting redeposition. A good solvent will not allow any paraffin to cling to the bottle.
A new approach to steamflooding extremely viscous heavy-oil reservoirs and tar sand deposits has been developed and tested successfully in the San Miguel-4 tar sand reservoir located in Maverick County, TX. The process is called fracture-assisted steamflood technology process is called fracture-assisted steamflood technology (FAST), and the first application in a tar sand was performed in a 5-acre (2-ha) inverted five-spot pilot pattern performed in a 5-acre (2-ha) inverted five-spot pilot pattern located on Conoco's Street Ranch lease. During a 31-month period, ending June 1980, the Street Ranch pilot produced 169,040 bbl (26 875 m3) of -2 deg. API pilot produced 169,040 bbl (26 875 m3) of -2 deg. API (1093-kg/m3) tar with monthly tar-production rates occasionally exceeding 300 B/D (48 m3/d). Postpilot core wells indicated residual tar saturations as low as 8% and an average recovery efficiency of better than 50%.
Low injectivity is frequently a problem when steamflooding heavy-oil reservoirs and it is almost always a critical limitation when working with extremely viscous tar sand deposits such as those in Canada, Utah, and Texas. One such resource is a 50-ft- (15-m-) thick layer of partially consolidated sandstone and hydrocarbon known as the South Texas tar sands. It is contained within the San Miguel-4 sand, which is found at a depth of around 1,200 to 2,300 ft (366 to 701 m) under some 90 sq miles (233 km2) of ranchland along the Maverick/Zavala county lines about 30 miles (48.3 km) northeast of Eagle Pass. Current estimates indicate that the San Miguel-4 sand contains between 2 and 3 billion bbl (0.32 to 0.48 km3) of -2 deg. API (1093-kg/m3) gravity tar. Conoco Inc. currently owns or has leased about 29,860 acres (12 084 ha) in the area known as the Saner Ranch field (Fig. 1), and has been working over the last 7 years to develop this particular resource. The unique properties of this resource base have made it necessary to develop new in-situ recovery methods to improve recovery efficiency.
San Miguel Tar Sand Deposit
The San Miguel-4 is the fourth in a series of nine sands deposited within the Taylor shale sequence of the Montana group. This places deposition during the upper Cretaceous period of the Mesozoic era. The northwesterly and updip location of each successive sand unit indicates that the San Miguel series is a product of an overall marine transgression. The San Miguel-4 deposit is predominantly sandstone with numerous irregular limestone intercalations. Its wide geographical distribution suggests that it represents a highly reworked deltaic deposit on a shallow marine shelf with occasional influence by an upper shelf, barrier bar, strand plain environment. The high degree of reworking was caused mostly by long shore currents during a fairly steady, moderate-energy period as indicated by the very low clay content, good sorting, and the presence of thin-shell pelecypods. A fairly high content presence of thin-shell pelecypods. A fairly high content of feldspars, from 10 to 45 %, indicates short exposure to weathering agents and implies rapid transport and burial.
The San Miguel-4 sand outcrops just north of the Maverick/Kinney county lines and dips to the south-southeast at a slope of 2 deg. At the southern edge of Conoco's property (Fig. 1) the formation is about 2,300 ft (701 m) deep. Gross thickness ranges from 20 to 80 ft (6.1 to 24.4 m), with the average close to 50 ft (15.2 m). Except for the interspersed limestone streaks, the sand is very clean, with a mean particle size of 110 microns (110 mu m) and a Schwartz uniformity coefficient of less than two. Its cleanliness and uniformity result in porosities of 26 to 30% and permeabilities of 250 to 1,000 md.
The San Miguel-1 sand in the Sacatosa field is in a low permeability formation and was considered noncommercial. Hydraulic fracturing and waterflooding have turned it into a profitable operation with an anticipated secondary recovery equaling the primary, and a projected life of over 35 years.
While conducting a geological investigation of the Chittim Arch anticlinal structure in 1956, Continental Oil Co. discovered the Sacatosa (San Miguel-1) field. It is located in Maverick County, Tex., near the Dimmit and Zavala County lines (see Fig. 1). When the drilling program was completed in the fall of 1968, there were program was completed in the fall of 1968, there were approximately 670 active wells in the field. The field has an areal extent of 11,500 acres, of which 11,000 acres are located on Continental Oil Co.'s N. J. Chittim lease. At first, the field was considered noncommercial. The potential of the discovery well was only 4 BOPD. After stimulation with nitroglycerin, production was increased to 8 BOPD. This low productivity led to an intensive study to determine if the San Miguel-1 could be commercially produced by the use of newer stimulation techniques.
Hydraulic fracturing was tried on two wells drilled during 1957. One well was fractured with 22,500 lb of sand in 16,590 gal of diesel oil; the potential, pumping, was 19 BOPD. The well was later refractured pumping, was 19 BOPD. The well was later refractured with 75,000 lb of sand and 51,240 gal of diesel oil. Following this fracture treatment, the potential, flowing, was 60 BOPD on a 11/64-in. choke. The second well was fractured with 90,000 lb of sand and 67,000 gal of diesel oil and flowed at a rate of 58 BOPD on an 8/64-in. choke. The performance of these three wells was studied to evaluate the feasibility of further development.
These studies indicated that the field could be commercially developed. A development program was begun in 1958 and, prior to the waterflood expansion in the Fall of 1967, a total of 483 production wells had been drilled and completed by Continental Oil Co. in the San Miguel-1 sand.
The San Miguel-1 sand is a member of the Upper Taylor formation in the Gulf series of the Cretaceous system of Mesozoic age. The Chittim Arch is the controlling geological structure in the Southwest Gulf Coast area. The San Miguel-1 sand pinches out or shales out updip against the flank of this structure, creating stratigraphic traps for oil accumulations. Sacatosa (San Miguel-1) field is the largest of a number of oil and gas fields that resulted from entrapment of hydrocarbons against the arch.
The Sacatosa (San Miguel-1) field is the result of shale-outs or permeability barriers on the south, west and north sides of the field. (See Fig. 2.) An oil-water contact has been established on the east and southeast sides, but it does not appear to be an active drive mechanism.
Minor faulting occurs across the field, which is of importance in only one instance: a fault closure has caused a gas cap to form and two wells have been shut in due to high GOR.
The sands were deposited initially as a beach of an old ocean.