Fracturing In Vertical Wells Research Articles

Numerical simulation of deflagration fracturing in shale gas reservoirs considering the effect of stress wave impact and gas drive

Methane deflagration fracturing is a new reservoir stimulation method that serves the efficient development of shale gas reservoirs. However, the propagation law of deflagration fractures is still unclear. In this paper, a numerical model considering the effect of stress wave impact and gas drive of deflagration fracturing was established based on the continuum–discontinuum element method (CDEM). The correctness of the numerical model was verified by comparing it with a laboratory experiment, the steady and unsteady analytical solutions of gas flow, and the approximate solution of fracture propagation. Then, numerical simulations of methane deflagration fracturing in vertical wells and horizontal wells under different factors were carried out to analyze the fracture mechanism. The results indicate that deflagration fracturing in vertical wells can break through the stress concentration around the borehole; the initial radial fractures are formed under the action of stress wave impact and then propagate substantially under the driving action of high-pressure gas. The in-situ stress difference affects the deflagration fracture propagation and makes the half-fracture length in the direction of maximum principal stress larger than that in the direction of minimum principal stress. The more significant the stress difference is, the more noticeable this deviation will be. When the deflagration peak pressure is high, the reservoir burst degree is large, which is conducive to enlarging the stimulation range of deflagration fracturing. Staged deflagration fracturing in horizontal wells can form 5–8 obvious fractures perpendicular to the horizontal borehole in each explosion section. A large cluster spacing and explosion section length are conducive to expanding the stimulation scope. Moreover, the propagation of deflagration fractures will be induced by the natural fractures, and the natural fracture with a considerable length or a slight angle between the dip angle and the propagation direction of deflagration fractures is more likely to be activated.

Study on Dynamic Disaster Mechanisms of Thick Hard Roof Induced by Hydraulic Fracturing in Surface Vertical Well

With the increase in mining depth and the deterioration of mining conditions, thick and hard overburden movement frequently induces mine earthquakes and rock bursts. Some mines are expected to prevent and control super thick hard rock mine earthquakes through vertical ground well water fracturing technology. However, the dynamic underground disaster appears more intense. Taking the ‘11.30’ mine earthquake in a mine in Shandong Province as the engineering background, the dynamic disaster mechanism of an extraordinarily thick and hard roof induced by hydraulic fracturing of vertical wells on the ground was studied utilizing field investigation, accident case analysis, similar material simulation test, and theoretical analysis. The main conclusions are as follows: (1) After hydraulic fracturing vertical wells on the ground, the movement mode of thick and hard roofs changed from layer-by-layer to overall sliding movement; (2) The influence range of the advanced abutment pressure of the working face is reduced by the hydraulic fracturing of the vertical shaft, and the peak value of the advanced abutment pressure increases. Furthermore, the advanced abutment pressure’s peak is far from the coal wall; (3) The hydraulic fracturing technology of cross-arranged vertical surface deep and shallow wells and the hydraulic fracturing technology of cross-perforated surface multi-branch horizontal wells are proposed to avoid the dynamic disaster of overall sliding movement of an extremely thick hard roof induced by surface hydraulic fracturing. Therefore, these research results provide significance for preventing and controlling mine earthquakes and rock bursts in super thick hard roof mines.

Research and application of large-scale fracturing imitating horizontal well technology in vertical well

Hailaer Basin is rich in geological reserves, but the proportion of undeveloped reserves is high, accounting for 30% of the proved reserves. In order to improve the production degree of reserves and single well production, and realize the purpose of high and stable production of the oilfield. Taking the ultra-low permeability reservoir of oilfield B in Hailaer Basin as an example, this paper puts forward the large-scale fracturing of vertical wells and water injection development technology of imitating horizontal wells. By forming directional ultra long fracturing fractures in the oil layer, this technology can effectively increase the reservoir conductivity, increase the oil well drainage area and water well control area, reduce the well pattern density and improve the production of single well. The research shows that the undeveloped reserves in Hailaer oilfield have the characteristics of low thickness, low permeability and low reservoir quality index. There are 55 large-scale mold fracturing wells in Hailaer oilfield, with an initial oil increase of 2.2 times. The sand amount of large-scale fracturing is 2.5 times that of ordinary fracturing, and the fluid amount and sand intensity are 4.5 times that of conventional fracturing. The vertical well large-scale fracturing imitating horizontal well technology is adopted in Oilfield B. The designed vertical well fracturing fracture is 600m long and 120m wide, and the production effect is good after fracturing. The research results are of great significance to the high and stable production of undeveloped reserves block in Hailaer oilfield and other similar oilfields.

Key Technology of Volumetric Fracturing in Vertical Wells of Hugely Thick Shale Oil Reservoirs in the Fengcheng Formation of the Mahu Sag

Shale oil reservoirs in the Fengcheng Formation of the Mahu Sag are characterized by a large buried depth of sandbodies, huge thickness, overall oil-bearing properties, dense matrix, and enrichment in metal ions. As a result, fracturing is prone to be insufficient in vertical extension and unable to cover the reservoir, with low fracture complexity, high sanding risks, and an incompatibility of conventional guar gum fracturing fluid. Based on a detailed description of reservoir mechanical properties and an evaluation of the main controlling factors of fracture networks, a calculation model of fracability index was built to fully exploit the exploration potential of the shale oil in this area. In light of the vertical fracture propagation, the perforation clusters and cluster spacing were determined to develop a fine vertical layered approach. In accordance with the development of natural fractures, the optimized volumetric fracturing technology was upgraded, and the net pressure in fracture was increased by construction with high pumping rate. Multi-scale filling was realized with the combination of proppants of different sizes, and a gradual pumping rate increase was employed to ensure safe sand adding. Further, a series of temperature-resistant and salt-resistant polymer fracturing fluids were developed. As a result, the key technology was developed for volumetric fracturing in vertical wells of hugely thick shale oil reservoirs in the Fengcheng Formation of the Mahu Sag. This technology has been successfully applied in Well MY1 in the shale oil reservoirs of the Fengcheng Formation, with a high-yield oil flow of 50 m3 per day after stimulation treatment. This started a new and promising prospect of unconventional reservoir exploration in the Mahu Sag, which is of great significance in guiding the subsequent shale oil development in this area.

Exploration domains and technological breakthrough directions of natural gas in SINOPEC exploratory areas, Sichuan Basin, China

Natural gas exploration in SINOPEC's exploratory areas in the Sichuan Basin has achieved rapid development. Since discovering the Xinchang gas field, natural gas exploration has expanded gradually, with both reserves and production growing fast. The deepening understanding of geological theory and crucial technology's progress is the main driving force for the natural gas industry's significant development. Considering the rich natural gas resources, various types of promising targets, exploration degree of 16% of conventional natural gas, and the initial stage of shale gas exploration, the HCZ model predicted natural gas exploration. Additionally, it indicated that the shale gas in the SINOPEC exploratory areas in the Sichuan Basin would consistently have rapid development with proven reserves increasing by (160–200) × 109m3/a. In the future, the development strategy is to vigorously develop shale gas, steadily promote marine conventional natural gas, and continually research continental tight sandstone gas. The following tasks need to be strengthened for efficient exploration of the three resource types: prediction of deep and ultra-deep reef-shoal reservoirs, weathered crust reservoirs, and technological breakthrough of efficient drilling and fracturing test of ultra-deep wells; the technological breakthrough of geological-logging-seismic integrated sweets pot prediction of tight sandstones and low-cost multi-layer fracturing of vertical wells; the technological breakthrough of increasing-yield and reducing-cost drilling, completion, and fracturing of deep marine shale gas; resources potential evaluation and adaptive exploration and development technologies preparation of continental and transitional shale gas.

Research on Investment and Daily Production Limit of Largescale Fracturing Productivity Project of New Vertical Well

Large-scale fracturing technology is a new type of fracturing technology developed in recent years along with the fracturing theory research of natural fractured reservoirs. The application of large-scale fracturing in vertical wells has achieved good production results. However, due to the short application time of new technology in oilfields and the low regularity of development indexes, there is no economic evaluation method for shaping. This paper evaluates the development effect of large-scale fracturing in Daqing Oilfield, clarifies the variation law of its development index, and establishes the index prediction method in the evaluation period. Through sorting out the various depreciation calculation methods used in economic evaluation, the appropriate modified production method is selected as the method of calculating depreciation. Based on the relevant data and results of economic evaluation of oilfield development, the economic evaluation method of large-scale fracturing technology productivity project has been formed, and the calculation program has been compiled. The program is used to calculate the investment boundaries of large-scale fracturing blocks with different single well daily production under the condition of multiple oil prices, draw the maps of single well investment and single well daily production boundaries under different oil prices in large-scale fracturing blocks, and analyze the sensitivity of investment boundaries. The research results will be applied in proven reserves submission, unused reserves evaluation and oilfield development planning. Using this method for reference, the boundary maps of conventional water flooding development and large-scale volume fracturing can be drawn, and the research results can be applied to a greater extent.

Transient-Flow Modeling of Vertical Fractured Wells with Multiple Hydraulic Fractures in Stress-Sensitive Gas Reservoirs

Massive hydraulic fracturing of vertical wells has been extensively employed in the development of low-permeability gas reservoirs. The existence of multiple hydraulic fractures along a vertical well makes the pressure profile around the vertical well complex. This paper studies the pressure dependence of permeability to develop a seepage model of vertical fractured wells with multiple hydraulic fractures. Both transformed pseudo-pressure and perturbation techniques have been employed to linearize the proposed model. The superposition principle and a hybrid analytical-numerical method were used to obtain the bottom-hole pseudo-pressure solution. Type curves for pseudo-pressure are presented and identified. The effects of the relevant parameters (such as dimensionless permeability modulus, fracture conductivity coefficient, hydraulic-fracture length, angle between the two adjacent hydraulic fractures, the difference of the hydraulic-fracture lengths, and hydraulic-fracture number) on the type curve and the error caused by neglecting the stress sensitivity are discussed in detail. The proposed work can enrich the understanding of the influence of the stress sensitivity on the performance of a vertical fractured well with multiple hydraulic fractures and can be used to more accurately interpret and forecast the transient pressure.

Semi Analytical Model for Predicting Screenout in Hydraulic Fracturing in Vertical Wells

Semi Analytical Model for Predicting Screenout in Hydraulic Fracturing in Vertical Wells

Challenges and Opportunities of Coalbed Methane Development in China

Coalbed methane (CBM) resources in China have been estimated to exceed 36 Tcm. As of 2014, there were ∼9300 producing CBM wells in China with an annual production of ∼4.4 Bcm. To satisfy its need for energy and to transition to a low-carbon economy, China has a big need to accelerate CBM development. This paper gives an overview of the status of CBM development in China, identifies key technical challenges, and proposes solutions to overcome them. Our review of the literature has revealed that current CBM development in China faces several technical challenges. Current projects are focused on high-rank coals in the Qinshui and Ordos basins, which have major geological and engineering challenges. The former includes low permeability, subhydrostatic reservoir pressure, and a lack of understanding of the connectivity of coal seams, which leads to difficulty in sweet spot indication. The latter includes difficulty in hydraulic fracturing in vertical wells, because of the ductile nature of the coal seams in th...

Simulating Multizone Fracturing in Vertical Wells

Numerous multizone multistage hydraulic fracturing treatments are now being executed in low permeability oil and gas fields around the world. Due to the limited access to the subsurface, post-treatment assessments are mainly limited to few techniques such as tiltmeter, microseismic, and tracer-logs. The first two techniques are mainly used to determine fracture extension; however, fracture height and fracture initiation at all perforation clusters could only be confirmed through radioactive tracer logs or detailed pressure analysis. In this paper, we consider real examples from a field from Central America and investigate potential problems that led to the limited generation of fractures in multizone treatments. For instance, some of the postfrac radioactive logs show very low concentration of tracers at some perforated zones in comparison with other zones. On the other hand in some cases, tracer logs indicate the presence of tracers in deeper or shallower zones. Different reasons could cause fracture growth in nonperforated zones, including but not limited to: perforation design problems, casing/cement integrity problems, lack of containment, instability of fracture growth in one or some of the zones, and finally making a mistake in selecting lithology for fracturing. In this paper, some of these issues have been examined for a few sample wells using treatment pressure data, petrophysical logs, and postfrac tracer logs. Some recommendations in designing the length and arrangement of perforations to avoid these problems in future fracturing jobs are provided at the end of this paper.

SIMULATING THE EFFECT OF NON-DARCY FLOW AND HYDRAULIC FRACTURING ON WELL PRODUCTIVITY IN A NATURALLY FRACTURED LEAN GAS CONDENSATE RESERVOIR

Condensate formation near the wellbore area of gas condensate reservoirs, below the fluid dew point, reduces the gas relative permeability and, consequently, decreases the well productivity. Alternative solutions including drilling horizontal wells, hydraulic fracturing in vertical wells, gas recycling, and increasing production rate can prevent the reduction of productivity. Hydraulic fracturing has been introduced as one of the frequently-used methods to enhance the productivity in gas wells. The main goal of this study is to numerically simulate the effect of hydraulic fracturing and non-Darcy flow on well productivity of an Iranian gas condensate naturally fractured reservoir by the CMG-GEM, which is a commercial simulator. The studied reservoir is of ‘lean gas condensate’ type at which the condensed volume is at most 1% of the total volume. The studied reservoir was modelled in two approaches. In the first model, the reservoir includes a network of natural fractures modelled by dual porosity approach; while, in the second model, single porosity method was used to model the reservoir. Both models were run in the existence of hydraulic fractures and without them. The outputs showed that hydraulic fractures did not affect the productivity index in the dual porosity model; however, such fractures increased the productivity index of the single porosity model. In the next step, non-Darcy flow conditions were added to the previous runs. Presence of the non-Darcy flow decreased the productivity index where the productivity reduction was substantial in the dual porosity model.

Characterization of a Shallow Horizontal Fracturing Treatment in Western Missouri

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102342, "Characterization of a Shallow Horizontal Fracturing Treatment in Western Missouri," by L.K. Britt, SPE, NSI Technologies Inc.; S. Dunn- Norman, SPE, U. of Missouri-Rolla; M.B. Smith, SPE, NSI Technologies Inc.; E. Atekwana, U. of Missouri-Rolla; L. Slater, Rutgers U.; A. Gupta, SPE, and D. Numbere, SPE, U. of Missouri-Rolla; J.V. Fontana and J.H. Viellenave, Direct Geochemical; and J. Pelger, SPE, J-Environmental Inc., prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. A research project, sponsored by the U.S. Dept. of Energy, was undertaken to demonstrate a development method for the heavy-oil reserves that exist at ultrashallow depth in southwestern Missouri and southeastern Kansas. The principal objective was to demonstrate an economically viable method of producing the shallow heavy oil by use of a combination of microbial-enhanced oil-recovery treatments and horizontal fracturing in vertical wells. Introduction Heavy oil (8 to 25°API) exists in the shallow Pennsylvanian sands that occur over approximately 8,000 sq miles along the Kansas/Missouri border. The area covers portions of the northeast Oklahoma platform and the Cherokee and the Forest City basins. The Cherokee group is a sequence of alternating shales and sandstones with thin coal and limestone beds. The main productive units within the Cherokee group are the Bluejacket and Warner sandstones. The Warner sand has been drilled throughout Vernon County, Missouri, and several areas of known oil deposits have been defined. In the latter part of 2000, seven boreholes were continuously cored to a total depth (TD) of approximately 220 ft. All wells encountered heavy oil in both the Bluejacket and Warner sandstones. The Bluejacket sand occurred at approximately 130 to 135 ft with 8 to 12 ft of net pay, and the Warner sand occurred at approximately 160 to 170 ft with 15 to 30 ft of net pay. Warner-sand porosity ranged from 14 to 25%, and permeability in the Upper Warner ranged from 100 to 400 md. Five wells were drilled to produce the shallow heavy-oil deposits in the Warner sandstone, the Fauvergue Wells 1 through 5 (Fig. 1). The Cushard Wells 4 and 5 were cored wells in the project area. These wells were cored to TD and the cores analyzed as part of the project. Although it was believed that older wells drilled in the Warner sandstone had been fracture stimulated, no information regarding any historical fracture treatments, execution, or performance was available. Geomechanical Data Set The geomechanical data set includes profiles with depth of Young's modulus, in-situ stress, and fracture-fluid leakoff. Core from the Bluejacket and Warner sandstone formations and surrounding shales was available from the coreholes drilled, and static triaxial compression tests were conducted on samples to determine Young's modulus. Evaluation of the triaxial compression tests indicated that the Bluejacket and Warner sandstones have an average Young's modulus of 3.1×106 and 1.3×106 psi, respectively. The Rowe coal and the bounding shales have an average Young's modulus of 2.0×106 and 1.8×106 psi, respectively.

Comparison of Methane Production From Coalbeds Using Vertical or Horizontal Fractured Wells

Summary Methane production from coalbeds, while originally a safety measure, hasemerged as a major source of gas for a number of locations worldwide. Gasdesorption is the main production mechanism. This is accomplished currently bythe production mechanism. This is accomplished currently by the hydraulicfracturing of vertical wells; draining of water, which is always present in thelimited pore structure; and reducing pressure to begin the desorption process. However, hydraulic fractures tend to propagate parallel to the main naturalfissures and thus normal to the smallest permeability. This is the leastfavorable position. Simulation shows that horizontal wells drilled in theorthogonal direction (i.e., normal to the maximum permeability and the mainnatural fissures) can provide significantly larger gas rates. Several smallhydraulic fractures, performed in the horizontal well with proper zonalisolation, can augment production further. Considering the highly fissured, cleated nature of coalbeds, small stimulations, with much more modestexpectations, are far easier to perform than the single treatments required ina vertical well. Design criteria, well sizing, and stimulation treatment numberand magnitude are calculated and presented. Introduction The coalbed methane industry has emerged as a significant source of naturalgas production. The original perception of coal-associated methane as a hazardin mining operations is becoming obsolete. Today, a coalbed is considered areservoir from which large quantities of methane can be extracted. In the U.S. alone, the total coalbed resource is estimated to be 4 × 10-13SCf [1 × 10-13 std m3], of which 9 X 10-13 SCf [2.5 × 10-12 std m3] isconsidered recoverable reserves. Several potential mechanisms have been identified during the production ofcoalbed methane, including free gas from associated production of coalbedmethane, including free gas from associated natural fractures and gasdesorption from the coal surface as the reservoir pressure declines. Primaryporosity in coals is very small, rarely exceeding 0.05, with typical valuesaround 0.02. Reservoir thickness is also very small (this is the thickness of acoal layer) and is frequently less than 10 ft [3.3 m]. Vertical wells, allowing exceedingly small contact between them and a coalseam, are rarely, if ever, acceptable producers. Production rates do not exceeda few thousand cubic feet a day, and Production rates do not exceed a fewthousand cubic feet a day, and they are hindered further by relativepermeability problems caused by the presence of associated water. Hydraulic fracturing of vertical wells in coalbeds has been attempted in anumber of cases. The perception of coal seams as fracturable reservoirsprompted the study of their rock and reservoir properties as they might affectfracture design. Several features distinguish coalbeds from other reservoirs. In addition tothe small thickness and porosity already mentioned, the (also small)permeability is usually highly anisotropic, with the maximum permeabilityinvariably along the maximum horizontal stress. This would make the hydraulicfracture parallel to the maximum permeability, which is, of course, highlyundesirable during production when the bilinear flow concept would necessitatea large permeability normal to the fracture face. Permeability anisotropy in coalbeds is caused by natural fissures Permeability anisotropy in coalbeds is caused by natural fissures that, although anisotropically distributed, are also at various angles along thehydraulic fracture path. These fissures may open during the treatment, providing large fluid leakoff paths, readily dehydrating the slurry, andresulting in screenouts. To combat this, fracture designs have used very smallproppant slurry concentrations (frequently 2 lbm/gal [240 kg/m3), leading tovery lackluster production rates. Also, fines migrating from the coal fissuresystem may penetrate the hydraulic fracture and reduce its conductivityfurther. Of the primary fracture treatment variables, the Young's modulus of coalbedsis very small (between 1 × 10-5 and 1 X 10-6 psi 16.9 × 10-8 to 6.9 × 10-9 Pa])compared with normal fracturing candidates with Young's moduli between 3 × 10-6and 10-7 psi [2 × 10-10 and 6.9 × 10-10 Pa]. In the best cases, this featurewould result in short, wide fractures instead of the long penetrations requiredby such low-permeability reservoirs. Finally, coalbeds to be fractured, presumed to be single reservoirs, presenta large variation in the success of the treatment because of stress variations. They are usually multilayered and are prone to T-shaped fractures. Thesefeatures and others, along with guidelines for adjusting fracture design modelsand recommendations for fracturing treatments, are presented later. Obviously, maximization of the gas production rate from coalbeds is theissue at hand. From all the above, it should not be too surprising thatproduction from unstimulated or hydraulically fractured vertical wells isusually small, ranging from 50 to 230 Mscf/D [1.4 × 10-3 to 6.5 × 10-3 stdm3/d] in 30 wells in an Alabama field 13 and a cumulative 6 to 7 MMscf/D [1.7 × 10-5 to 2 × 10-5 std m3/d] from another 31-well development. A no-proppant foamstimulation in a well was reported to result in an average 4.5-month productionof 49 Mscf/D [1.4 × 10-3 Std m3/d]. production of 49 Mscf/D [1.4 × 10-3 Stdm3/d].