Fracture Stimulation Treatments Research Articles

Equipment And Procedures Shortcut Results In Uncontrolled Flow — A Case Review

Abstract It is imperative that a completed well be adequately equipped to fully control the flow of any fluid from the well at all times. Regardless of the nature, size or type of equipment that an operator may be running in or out of the wellbore, the procedure must assure that the wellhead, blowout prevention equipment and any other ancillary equipment be capable of providing that control. Two accepted practices are to either fill the wellbore with a fluid of sufficient density to create a hydrostatic head that exceeds or balances the pressure of formation open to the wellbore, or to perform live well servicing. The latter involves snubbing the production tubing or working string into and out of the well under pressure. The snubbing method is used when there is a concern that kill fluids could damage the formation inflow capacity of the well. This case reviews a failure to control a gas well while snubbing out a working string with variable diameter tools being used to retrieve a tubing conveyed perforating gun from a well in Alberta. The well had been perforated, briefly flow tested and was being prepared for a fracture stimulation treatment. Drilling and Initial Completion History A well license was issued on January 23, 1986, for the well, Lac ef al. Minehead 6-18-49-17 to be drilled for the purpose of obtaining production from the Cardium formation at a projected depth of 2440 m. Figure 1 shows the location of the wellsite, approximately 35 km south of the Town of Edson, in west central Alberta. The well was spudded February 4, 1986, and drilled to total depth by March 7, 1986. As shown in Figure 2,139.7 mm casting was run to 2436 m and cemented. A 60.3 m tubing was run in the well and the Cardium Sandstone was perforated from 2385.5 m on March 18, 1986, using a tubing conveyed perforating gun (TCP). A 38 m3 liquid CO2 stimulation squeeze was conducted on March 19, 1986. A modified isochronal backpressure test and final pressure buildup were conducted during the period March 26, 1986 to April 13, 1996. The results indicated limited inflow, an AOF of less than twenty 101 m3/d with some condensate. The shut in sand face pressure was 23,270 kPa. The final tubing pressure was 16,170 kPa and the final casing pressure was 16,690 kPa. Because of the limited flow capacity of the well it was decided that a fracture stimulation treatment was necessary to make the well capable of commercial production. The information presented in this paper up to the section "Well Control Operations" was gathered from interviews and discussions with representatives of the licensee, some contractors, other government agencies and ERCB field staff sent to the site immediately after the initial notification of the blowout. The well control presentation is based on ERCB field staff observations and the authors were on site for the last two days of the well control operation.

Effective Hydraulic Fracturing Of The Lower Amaranth Formation In Southern Manitoba

Abstract The Spearfish, or more properly, Lower Amaranth Formation in southwest Manitoba is a low permeability sandstone reservoir containing low GOR light oil. Wells drilled into this formation are generally not capable of commercial production until after a hydraulic fracturing stimulation. Factors such as an underlying water zone, along with an unconfined producing interval, have resulted in numerous hydraulically fractured Lower Amaranth wells producing water rather than-oil, limiting potential field development. Following the unsuccessful stimulation of several wells in the South Pierson field where hydraulic fractures propagated into the underlying water zone, a comprehensive re-evaluation and detailed design effort was implemented to minimize the potential for water production. The project incorporated geological studies; reservoir rock elastic properties determination and correlation with wireline logging techniques; determination of horizontal in situ stresses; reservoir performance testing; in situ fracture fluid performance evaluations; and two- and three-dimensional fracture geometry modelling techniques. It has resulted in new treatment designs incorporating fracture diversion anti-net pressure control techniques. This paper discusses the general stratigraphy of the Lower Amaranth zone and the completion requirements. Presented are the design concepts, data analyses and results of a number of Lower Amaranth Formation stimulations. Optimal treatment considerations and guidelines are provided to minimize the probability of water production following hydraulic fracture stimulation. Introduction Hydraulic fracturing has long been the most economic technique for the purpose of stimulating low permeability reservoirs and providing for commercial production of oil and gas. The success of fracture stimulation treatments depends primarily on achieving large contact area with the production interval and providing a large permeability contrast and high flow capacity within the fracture. Ideally, the hydraulic fracture created should extend laterally within the zone of interest, however, it is well known that substantial vertical fracture propagation may also occur, significantly impacting the success of the treatment. Complicating factors such as underlying water zones or overlying gas sections can be easily penetrated and subsequently reduce or eliminate any sought after oil production. BenNaceur and Touboul(12) considered the problem of a vertical fracture intersecting a formation with the underlying water zone. Several factors have been shown to influence the production of such a system, including the fracture extent and its distance from the water transition zone, its dimensionless conductivity, the vertical permeability or absence thereof, the relative permeability curves, and finally the mobility ratio between oil and water. It was shown that in addition to the benefit of increasing productivity, hydraulic fracturing resulted in a significant delay of the water breakthrough, even with values of vertical permeability being one-tenth the horizontal one. The major concern in the current study was to avoid any fracture propagation through an underlying low-permeability interval downward into a porous dolomite section that would have resulted in water breakthrough using the fracture as a flow path. Additional motivation for control of fracture height growth was to increase the effectiveness of the treatment by decreasing the extension into non-producing intervals and to reduce the over-all cost of the treatments.

How To Engineer a Fracturing Treatment

There are many causes of abnormally low well production rates, and a good engineering approach should identify them. They include low permeability, low reservoir pressure, high bottomhole pressure (BHP), high reservoir fluid viscosity, and high skin. The remainder of this paper considers the elements that can contribute to a successful hydraulic-fracture-treating program. Not all the elements need to be done in every case. However, they should be considered carefully, because they might affect both the success and the interpretation of the fracture-stimulation treatment. Inadequate evaluation could fail to identify changes and improvements to include in subsequent treatments. The following sections cover the pretreatment, execution, and evaluation phases of hydraulic fracturing. As can be appreciated, the key phase in fracture design is the pretreatment analysis.

A Case Study of the Wilcox (Lobo) Trend in Webb and Zapata Counties, TX

Summary The Wilcox (Lobo) trend of Webb and Zapata counties, TX, is a series of geopressured, low-permeability sands with average depth from 5,000 to 12,000 ft [1525 to 3660 m]. More than 1,000 wells have been drilled in this prolific trend during the last 10 to 12 years. Although actively developed earlier, the trend became even more attractive after its classification by the Federal Energy Regulatory Commission (FERC) as a "tight" gas formation. Essentially, development of the Wilcox (Lobo) has been successful because of modern technological advances. This paper presents the results of several years of study involving the geologic history, completion methods, massive-hydraulic-fracture (MHF) stimulation treatments, reservoir evaluation, and numerical analysis of hydraulically fractured wells in this trend, all of which illustrate the application of this modern technology. Introduction Low-permeability gas reservoirs have been developed actively in the U.S. during the past 10 to 15 years. Three of the most important criteria for the successful development of any area are (1) gas market availability, (2) gas prices adequate to justify the risks involved, and (3) proper prices adequate to justify the risks involved, and (3) proper application of modern technology. A key element is the development and transfer of the technology necessary to develop low-permeability gas sands economically. Many authors have contributed to the transfer of technology during the past few years by presenting papers concerning fracture fluids, fracture design equations, pressure-transient analysis, and other specific topics, pressure-transient analysis, and other specific topics, Papers that describe a field case history are normally Papers that describe a field case history are normally quite useful to most petroleum engineers. This paper presents the results of several years of work involving the geopressured Wilcox (Lobo) formation in Webb and Zapata counties, TX, including the geologic history, completion techniques, hydraulic-fracture stimulation techniques, and reservoir evaluation of the Lobo formation. In the 1960's, several wells were drilled and tested in the Wilcox (Lobo) formation. Because of low gas prices and a lack of pipelines, however, the area was considered uneconomical and remained inactive for several years. Successful production from the Wilcox (Lobo) sands in Mexico renewed interest in this trend in the early 1970's. Consolidated Oil and Gas Co. drilled its N.H. Clark Well 1 directly across the Rio Grande from established production in Mexico. This well produced at rates of up to 7.0 MMcf/D [198 × 10(3) m3/d] and officially discovered the Wilcox (Lobo) trend in the U.S. Early exploratory drilling, which was concentrated near the U.S./Mexico border, soon established the Wilcox (Lobo) trend as a major gas-producing horizon. As drilling progressed farther from the border, the Lobo was encountered at greater depths and the productive extent of the Lobo was expanded to include an area of at least 1,800 sq miles [4660 km2]. Even though the shallower sands near the border seem to produce at higher initial rates than the deeper sands, virtually every well drilled in the Lobo trend is fracture-stimulated to increase gas flow rates and recoverable reserves. As a result, MHF technology has been used quite extensively, particularly in the deeper areas. Because fracture stimulation costs can amount to a significant fraction of the total well costs (10 to 20%), it is important to optimize this phase of the completion. State-of-the-art analysis techniques, such as numerical history-matching simulation, have been used by many operators in an effort to optimize and to ensure effective fracture stimulation treatments. Even though more than 1,000 wells have been drilled, the Lobo sands are far from being completely developed. The productive limits of the trend are still being explored, with wells being drilled farther to the north, east, and south of the U.S./Mexico border. In these directions, the sands dip to depths of approximately 10,000 to 12,000 ft [3050 to 3660 m]. Because of the abnormally high pore-pressure gradients associated with these depths, the pore-pressure gradients associated with these depths, the drilling and completion techniques must be well integrated.

The Utility of CO2 as an Energizing Component for Fracturing Fluids

Summary The use of CO2 as an energizer in hydraulic fracturing fluids has increased dramatically in the past few years. The history of CO2 usage for this application is discussed briefly, and CO2 is compared with the other commonly used energizer, N2. The design considerations for using CO2 in a fracturing treatment, both as a minor (energizer) and a major (foam) component, are presented. Special consideration is devoted to CO2 foam because CO2 is pumped as a compressible liquid that changes to a gas downhole. This paper presents the calculations required to estimate the surface liquid CO2 volumes and injection rates needed to obtain the desired downhole foam properties. Also, the instrumentation required to meter the liquid CO2 safely and accurately is discussed. Field results further evidence CO2's utility in hydraulic fracturing. This discussion includes a comparison of fracture stimulation with and without CO2 as an energizer as well as treatments that compare CO2 -energized fluids with N2-energized fluids. Economic considerations of pumping CO2 vs. N2 vs. no energizer are discussed. Conclusions suggest what further study is required to help improve design techniques and when CO2 should be considered as a component of a fracture stimulation treatment.

Proppant Selection: The Key to Successful Fracture Stimulation

Summary Many proppants and mesh sizes are available for thedesign of a fracture stimulation treatment. When proppants-sand (Ottawa, Texas Mining, Unisil), proppants-sand (Ottawa, Texas Mining, Unisil), bauxite, intermediate-strength proppants (ISP), resin-coatedsand (RCS), precured resin-coated sand (PRCS) and Zprop-are considered, the principal questions seem to be, prop-are considered, the principal questions seem to be, "Which one do I select"" and "How should I use it?"Maximized, adequate, long-term productivity inlow-permeability reservoirs depends on fracture penetration and fracture conductivity. How to obtain deeply penetrating fractures that are contained and adjacent to the porous penetrating fractures that are contained and adjacent to the porous interval is one of the questions that challenge the industry. Another is how to obtain sufficient fractureconductivity to use the deep penetration effectively. This is a state-of-the-art paper that attempts to bring the current technology on proppants together. This paper discusses how to determine and to obtain sufficient fracture conductivity. Fracture conductivity is a function ofthe proppant properties (i.e.. strength, roundness, andfines content), closure stress, drawdown rate, formation properties (i.e., proppant embedment conditions), and properties (i.e., proppant embedment conditions), and resultant propped fracture width. The engineering, principles involved in the selection of-the proper type and principles involved in the selection of- the proper type and amount of proppant are supported with a case history. Introduction As we explore for reserves at depths exceeding- 10.00ft 13,048 in], the tendency is to find reservoirs that havelow permeability and contain natural gas. Because of thelow permeability of the formation, the natural rateof production and the drainage area are often too low toprovide a commercial well. provide a commercial well. Propped hydraulic fracture-stimulation treatments thatcreate deeply penetrating, highly conductive flowchannels can be used to increase both the rate of productionand the drainage area. Four factors control improvements in productivity (i.e., the productivity index) provided by hydraulic fracturing.Propped fracture area (sq ft). This is the area of thefracture adjacent to the porous interval that has beenpropped (length times height). All the fracture area propped (length times height). All the fracture area adjacent to the porous interval that is created have not bepropped, and only the fracture area adjacent to the propped, and only the fracture area adjacent to the productive porosity that is propped is considered an effective productive porosity that is propped is considered an effective area.Conductivity of the propped fracture (md-ft). Thisis a measurement of how well the propped fractureconducts the produced fluids. In addition to the effectof closure stress on the permeability of the proppant, factors such as embedment. proppant distribution, andresultant fracture width must be considered to determine theconductivity of the fracture at reservoir producingconditions.Reservoir permeability. This value is used todetermine the fracture conductivity required to use theproposed fracture penetration effectively. proposed fracture penetration effectively.Drainage radius. This value is used, as is reservoirpermeability, to determine the length of fracture needed. permeability, to determine the length of fracture needed. A long, fracture is needed if the well spacing is large andthe reservoir permeability is low. Typical Well To show how the principles that are described in this paperwork, we will use a typical gas well with the propertiesdescribed in Table 1. Effect of Reservoir Permeability on Fracturing. Indeep, hot, low-permeability sandstone reservoirs, development of deeply penetrating fractures with adequate conductivity is important. Once reservoir permeability isknown, it is important to optimize the fracture length andconductivity by comparing treatment cost to expected production. The pressure drop along a propped fracture that production. The pressure drop along a propped fracture that has an insufficient flow capacity will limit the productionfrom a well. A fracture with excessive fracture capacityis not effective. Fig. 1 can be used as a guide in the selection of the desired effective fracture length based on reservoir permeability. When the reservoir permeability is greater than permeability. When the reservoir permeability is greater than about 0.1 md, the desired fracture lengths are generally1,000 ft 1305 mi or less. In low-permeability reservoirs(kg, less than 0.1 md), production can be almost directly proportional to fracture length before boundary conditions are proportional to fracture length before boundary conditions are reached. With adequate fracture flow conductivity, thelonger the fracture, the higher the producing rate. For example, in very-low-permeability reservoirs (i.e., 0.001 to 0.0001 md), fracture half-lengths of 2.500 to 4,000 ft 1762 to 1220 nil can be used to increase production effectively. Fig. 1 shows that in the typical well example with a permeability of 0.03 md. a 1,300-ft [396-m]fracture half-length should be created and propped to achieve maximum production. Effect of Fracture Conductivity and Fracture Length on Production. Fig. 2 was generated with a reservoirsimulators and shows the effect of fracture conductivity(Cf) and fracture half-length on production in dimensionless terms. JPT P. 2163

Stimulation Design for Upper Morrow Reservoirs in Reydon-Cheyenne Area, Western Oklahoma: ABSTRACT

Recent deep, high-pressure upper Morrow reservoir completions in the western Oklahoma part of the Anadarko basin indicate the area to be a major natural gas producing area. These Morrow sandstone reservoirs consist of poorly sorted medium to coarse-grained feldspar-rich sandstones to chert-pebble conglomerates. Diagenetic minerals present include calcite, siderite, and quartz overgrowths. Clay minerals present include small to moderate amounts of iron-rich chlorite, mixed-layer clays, and illite. Generally, the diagenetic minerals and the clays tend to fill the intergrain pore space. Reservoir porosity ranges from 6 to 12%, and effective reservoir permeabilities range from 0.1 to 10 md. Wells are generally drilled to total depth, logged, and a 5-in. (12.7 cm) OD liner is cemented back to the intermediate casing. Once perforated and cleaned up, the well is allowed to flow and a pressure buildup test is performed. Buildup-test analysis commonly indicates that a fracture-stimulation treatment may be needed to obtain satisfactory production rates. With bottom-hole temperatures in excess of 260°F (127°C), potassium chloride treated water in a cross-linked gel system is being used as the treatment fluid. Use of high-strength proppant instead of sand appears to help provide sustained production increases after fracturing. Treatment designs must consider the following parameters: depth, bottom-hole temperature, reservoir pressure, and bottom-hole treating pressure, as well as surface-pressure limitations, tubing size, job volume, and type of proppant system used with respect to closure stresses expected. Following the stimulation treatment and fluid cleanup, another pressure-buildup test is performed to evaluate the treatment. Field results indicate that stimulation treatments have been successful. End_of_Article - Last_Page 2119------------

A New Method for Providing Increased Fracture Conductivity and Improving Stimulation Results

The effectiveness of the propping agent has a great bearing on the success of a fracturing treatment. A proppant bed with low intergranular permeability results in poor well performance. This paper presents a method for creating a propped fracture where the performance is dependent on the flow channels between spaced beds of proppant. Introduction The success of a fracturing stimulation treatment is dependent on the strength and distribution of the propping agent used to prevent the created fracture from closing after the treatment. A method is presented in which the proppant is distributed in a planned spaced manner throughout the fracture separated by stages of flush fluid. In this periodic propped method, the proppant stages function as periodic propped method, the proppant stages function as pillars to hold the fracture surfaces apart so the fluid pillars to hold the fracture surfaces apart so the fluid may flow between the proppant beds. The flow capacity of an open crack is several orders of magnitude greater than that of a bed of proppant. The design of the staging is discussed and the mathematical model it is based on is given. Treatments in the field are discussed and results are given for three areas. Significant production-increase values have been realized. Background It is generally accepted that increased productivity resulting from hydraulic-fracturing stimulation treatments is dependent on the effectiveness of the propping agent used. The vertical fracture Aces are held apart during the fracturing treatment by the friction pressure caused by the flow of the fracturing fluid. However, when the treatment ends and this friction pressure is no longer present, the fracture opening closes under the influence of the tectonic stresses. In fracturing treatments, some type of granular propping agent, such as sand, is transported into the propping agent, such as sand, is transported into the fracture to hold the faces apart. The proppant bed that fills the fracture may have a fluid conductivity hundreds of times greater than the formation. This proppant-filled channel serves to increase the effective drainage radius of the wellbore and increase the well's producing rate. A number of authors have discussed the importance of the conductivity of the fracture with respect to the production improvement realized. production improvement realized. The ratio of fracture conductivity to formation permeability (C/ki) generally should be greater than permeability (C/ki) generally should be greater than 10,000:1 if the full benefit of the propped fracture is to be realized. The effect of fracture conductivity on the production increase may be illustrated by the curves in Fig. production increase may be illustrated by the curves in Fig. 1. For a well on 40-acre spacing with rw = 0.33 ft, the constant on the abscissa (RCF) would be 0.006. Thus, a C/ki ratio of 10,000:1 will result in RC (relative capacity) = 60, and the Jfs/Ji values are near maximum for any L/re value. If the formation permeability (ki) was 0.1 md, a fracture flow capacity of 1,000 md-ft would be needed for C/ki = 10,000. Fig. 2, the flow capacity of 20-40 sand, shows that such a flow capacity could be obtained at concentrations above 1,000 lb/1,000 sq ft of propped area. However, if the formation permeability was much greater than 0.1 md, it would be necessary to use a proppant with much higher flow capacity. This generally proppant with much higher flow capacity. This generally means a larger grain size, which increases the probability of grain crushing and sand-out. At some higher formation permeability it might not be possible to obtain sufficient conductivity using possible to obtain sufficient conductivity using conventional propping methods and materials. JPT P. 1319

Vertical Fracture Height-Its Effect on Steady-State Production Increase

Data taken from a steady-state electrolytic model have been used to developcurves showing production increase as a f unction of fracture height, fracture length, reservoir height, drainage radius, fracture flow capacity, formation permeability and wellbore radius. The work allows a fullerevaluation of the effect of fracturing parameters on productivityincrease. Introduction Hydraulic fracturing methods for productionstimulation have become a common procedure in the oiland gas industry. Fracturing treatments areperformed on wells of various potentials to help increasethe production rate. In addition to the desire forincreased production is the need to predict whatincrease might be expected. This knowledge is usefulin economical treatment planning to accomplish thedesired production goals for the well. Theoretical production increases due to horizontalradial fractures may be calculated using equationsdeveloped from mathematical analyses and electricalmodels. It also is possible to predict theoreticalproduction increases due to vertical fractures usingcurves developed from electrical and mathematicalmodels." However, these studies assumed that thevertical fracture height and the formation height wereequal, which may not be true." In addition, the finalfracture height through which fluid is produced maynot be equal to the created height. The development of vertical fracture proppanttransport relationships has made unrealistic theassumption that propped fracture height is equal tocreated fracture height. Through the use of publishedproppant transport equations, it is possible tocalculate the height of a bed of propping agent depositedin a fracture of a given height. Assuming that thefluid flowing in the fracture moves through only thepropped portion of that fracture (i.e., that theunpropped part of the fracture heals) it becomesessential to know how production increase varies with theratio of propped fracture height to formation height. It should be recognized that future investigationmay determine that the fracture does not healcompletely and that a highly permeable channel existsover the deposited bed of proppant. The effect of thischannel was not considered for the present study. The following analysis of experimental dataallowed development of curves to determinetheoretical production increases considering fracture heightas a variable. Discussion In designing a fracturing stimulation treatment anumber of variables must be considered. The size ofthe treatment, type of proppant used, proppantconcentration, treatment fluid properties and wellconditions are all factors affecting the dimensions andpermeability of the fracture. Production increase due to a vertical fracture isaffected by propped length, height, width andpermeability of the fracture for a given set of formationconditions. Production increase may be defined asthe ratio of production rate after fracturing to theproduction rate before fracturing at the samepressure differential, pe - pw. JPT P. 633ˆ