Perforated Intervals Research Articles

Estimating Effective Fracture Pore Volume From Flowback Data and Evaluating Its Relationship to Design Parameters of Multistage-Fracture Completion

Summary Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.

A METHOD OF LIMITING THE INFLOW OF BOTTOM WATER IN OIL WELLS

The paper describes the method of isolation of bottom water inflow in oil wells. The method of isolation of inflow of formation water in the well, watered by water cone flowing into the near-wellbore area, is drilling is carried out from the main borehole of the stopped well into the productive formation with water intrusion into radial offshoots along the radiusbelow of the well perforation interval. They pump the waterproofing composition into referred radial offshoots with the creation of the waterproofing screen along the radius of the main wellbore. They leave the well for a period of reaction of composition injected under pressure and perform a subsequent well completion through existing perforations of the perforated interval.

Numerical Simulation of the Depressurization Process of a Natural Gas Hydrate Reservoir: An Attempt at Optimization of Field Operational Factors with Multiple Wells in a Real 3D Geological Model

Natural gas hydrates, crystalline solids whose gas molecules are so compressed that they are denser than a typical fluid hydrocarbon, have extensive applications in the areas of climate change and the energy crisis. The hydrate deposit located in the Shenhu Area on the continental slope of the South China Sea is regarded as the most promising target for gas hydrate exploration in China. Samples taken at drilling site SH2 have indicated a high abundance of methane hydrate reserves in clay sediments. In the last few decades, with its relatively low energy cost, the depressurization gas recovery method has been generally regarded as technically feasible and the most promising one. For the purpose of a better acquaintance with the feasible field operational factors and processes which control the production behavior of a real 3D geological CH4-hydrate deposit, it is urgent to figure out the effects of the parameters such as well type, well spacing, bottom hole pressure, and perforation intervals on methane recovery. One years’ numerical simulation results show that under the condition of 3000 kPa constant bottom hole pressure, 1000 m well spacing, perforation in higher intervals and with one horizontal well, the daily peak gas rate can reach 4325.02 m3 and the cumulative gas volume is 1.291 × 106 m3. What’s more, some new knowledge and its explanation of the curve tendency and evolution for the production process are provided. Technically, one factor at a time design (OFAT) and an orthogonal design were used in the simulation to investigate which factors dominate the productivity ability and which is the most sensitive one. The results indicated that the order of effects of the factors on gas yield was perforation interval > bottom hole pressure > well spacing.

Preliminary study on the CO2 injectivity and storage capacity of low-permeability saline aquifers at Chenjiacun site in the Ordos Basin

Deep saline aquifers are a promising choice for geological carbon dioxide (CO2) sequestration due to their greater storage capacity compared to other geological storage options. Injectivity and storage capacity are key concerns especially considering injection of CO2 into low-permeability reservoirs. Estimation of the CO2 injectivity and storage capacity was conducted with an analytical method and dynamic numerical modeling for an active demonstration site (Chenjiacun) of CO2 sequestration in the Ordos Basin. The analytical estimate of the mass injectivity of the Liujiagou reservoir is 4.06×10−6kgPa−1s−1, which is about 64% of the injectivity of the entire reservoir system, followed by the Shiqianfeng unit, which accounts for some 15.8%. The maximum injection rate for the Liujiagou reservoir was estimated to be roughly 15.1kg/s, leading to 476,000t of CO2 injected per year. The maximum injection rates for the other four reservoirs are substantially smaller than that for the Liujiagou reservoir. The injectivity of the Liujiagou reservoir estimated by numerical simulation ranges from 0.7 to 3.0×10−6kgPa−1s−1. The injectivity of the Shiqianfeng reservoir was estimated to be from 0.2 to 1.1×10−6kgPa−1s−1. The injectivities of the remaining reservoirs (i.e., Shihezi downward) are smaller than 0.6×10−6kgPa−1s−1. The maximum injection rate estimated from the numerical simulation is approximately 17kg/s, leading to 536,000t storage of CO2, with the injection pressure limited to 1.5 times hydrostatic pressure. The annual CO2 storage capacity of the Chenjiacun site is estimated to be 0.53–0.69Mt, for a single vertical injection well. About 5 injection wells may be required to deal with the current CO2 emission rate from CSCLC coal liquefaction processes, which is about 3Mt per year.The injectivity and storage capacity at Chenjiacun are not much smaller than that at In Salah and Ketzin, owing to the relatively great thickness and long perforated interval at Chenjiacun. In order to improve the reservoir injectivity and storage capacity further at Chenjiacun for large-scale CO2 storage in the future, possible injection strategies and reservoir management options include introduction of stimulation measures and water-production wells at approximately 1000m or even further away from the injection well, as well as using fully penetrating vertical wells with long perforated intervals.

A case study on the effective stimulation techniques practiced in the superposed gas reservoirs of coal-bearing series with multiple thin coal seams in Guizhou, China

The superposed reservoirs of coal-bearing series represent a new type of gas reservoir associated with coal seams, and those with multiple thin coal seams are an important subtype popular in Guizhou, an emerging area for coal-bearing series gas exploitation in China. So it is significance to accommodate hydraulic fracturing, a common stimulation technique for enhanced gas recovery from low permeability reservoirs, to the reservoirs there. Based on a number of engineering and test data from Songhe pilot project for coal seam gas recovery in Guizhou, this paper presents some effective stimulation techniques adapting to the superposed reservoirs of coal-bearing series with multiple thin coal seams, including drilling and well completion selection, gas-bearing intervals targeting, small-layer perforation, staged fracturing, ball sealer diversion and graded proppant injection. The study also focuses on the mechanism on adaptable hydraulic fracturing of the superposed reservoirs associated with multiple thin coal seams, by combining theoretical analyses and actual fracturing curve diagnoses. The results indicate that the fractures opening exhibit a certain temporal order depend on mechanical and other physical properties differences among individual perforated intervals, and the fracture opening sequence can be controlled by adjusting pumping scheme and dropping ball sealers; the fracture height extended into the adjacent rocks is a critical geometric parameter affecting scale of fracture network, and negatively correlated with tensile strength difference between coal seams and adjacent rocks; under a condition of the current maximum pump rate, the fracturing treatment in both multiple thin coal seams and interlayered sandstones have been implemented, and a fracture network has been generated with a uniform fracture geometry and strong flow conductivity by the combined application of the effective stimulation techniques.

Modeling of the Initial Adjustment Parameters of Petroleum Recovery Control Systems. Part 1. Degrees of Detail and Formulation of Models of Vectors of Variables with Disturbances

Features in the process of modeling the vectors of the input and output variables of petroleum recovery process control systems with different degrees of detail of their structures are considered. Methods of monitoring discharges of liquids at perforated depth intervals of water injection and petroleum producing wells of oil and gas deposits as the basic condition for implementing a real-time regime in these systems are proposed. Conditions for increasing the precision with which the parameters of the variables are monitored based on the hardware components employed in measurements of complex borehole media are considered.

SQUEEZE CEMENTING OPERATION TO CONTROL WATER PRODUCTION ON WELL OKTA-36 OF FIELD OKTA, EAST JAVA

This thesis mainly discuss about workover (Squeeze Cementing) evaluation Activity in OKTA-36 well of OKTA field, East Java. The choice to did a workover activity in this well was because the oil and gas production for this particular carbonate well has been depleted. The cause of this problem was the watering problem near wellbore as the problem was found by using the Chan’s Diagnostics. Chan’s diagnostics is one of a method to determine the watering problem by comparing days to the existing production data. To increase the oil and gas productivity of this well, the justification was to close the old perforation interval of 6300ft – 6330ft MD by squeezing cement activity and then move the perforation interval to 6195ft – 6205ft MD and 6220ft – 6230ft MD. To fix the wellbore problem caused by water, the interval of 6260ft – 6262ft MD was also squeezed. The choice of 6260ft -6262ft MD was based on the tightness of the formation because of the total loss characteristics of the well. The result shows that the workover activity was a success because of the massive increase in oil and gas productivity. The numbers for the production performance analysis after workover activities are the WHP of 925 psi, WHT of 122o F, FLP 280 psi, Choke 30/64”, oil production 1242 BOPD, Water Cut 0% and Gas Production 0.950 MMSCFD

Cyclic Steam Stimulation Effect on Skin Factor Reviewed Case Study

High oil viscosity is a major concern for recovery from heavy oil reservoir. Introducing heat to the formation has proven to be an effective way to improve mobility. The Heat transfer to the oil and reservoir rock is good for thermal recovery. The thermal recovery involves a well-known technique of cyclic steam stimulation which actually effect the nearby well area. Heavy oil reservoir which uses the thermal technique will experience the change of property. Fula North East (FNE) Sudanese field is located in the north-eastern part of Fula sub-basin. According to the development program of FNE, Bentiu layer (of Bentiu group) is the targeted reservoir where the pressure gradient is 285.65 psi/100m, perforation intervals is 540-533 m, and the average oil production rate of single well by applying the cyclic steam stimulation (CSS) is 236 bbl/d. For well- Q, (one of the hot wells) to void the bottom water the average production rate is 191 bbl/d. A minor change is observed in the key properties of the well when the skin affect is varied.

Smart completion design in cyclic steam stimulation process: an alternative for accelerating heavy oil recovery

Cyclic steam stimulation (CSS) has succeeded in recovering bitumen and heavy oil. However, after the fifth cycle, the process is no longer effective as indicated by the increasing cumulative steam-oil ratio (cSOR). This paper proposes an improvement to the CSS performance by modifying the completion design. The perforation interval is divided into two parts: upper section (for injection) and lower section (for production). In such design, the injected steam would condense due to heat loss. The steam would then flow to the lower section because of gravity force and the oil starts to produce. The injection-production cycle is managed by an interval control valve (ICV). Simulation results show that the proposed design would reduce the cSOR up to 30% and increase the cumulative oil production by 3.5 times. It is also revealed that the longer the distance between the injection and production sections, the better the steam efficiency. [Received: July 11, 2014; Accepted: March 22, 2015]

An integrated site characterization-to-optimization study for commercial-scale carbon dioxide storage

Injection of supercritical carbon dioxide (scCO2) into deep saline aquifers is considered a promising option to mitigate global climate change. At a storage site, the main objectives of carbon dioxide sequestration are to maximize the volume of scCO2 injected and minimize the leakage risk, while effectively managing formation fluid pressure buildup and the brine displaced by scCO2. An integrated characterization-to-optimization study is carried out for potential commercial-scale deep saline aquifer carbon dioxide storage proposed in western Wyoming. A three-dimensional heterogeneous reservoir model is built for which petrophysical and fluid flow parameters are populated using field characterization data and state-of-the-art laboratory measurements. The measured scCO2 relative permeability end point is low compared to previous measurements on similar sandstones, which poses a challenge for CO2 flow, formation pressure control, and storage efficiency. By carefully selecting a set of optimal well locations, perforation intervals, and bottomhole pressure constraints that lead to maximum CO2-in-place and minimal CO2 breakthrough at the producers, an injection rate ranging from 10.8 to 15.1Mt/year is achieved for a duration of 50 years. After scCO2 injection ceases, up to 62% of the total injected scCO2 can be immobilized as residual scCO2 in 1000 years. Because of the low scCO2 relative permeability end point, post-scCO2-injection chase brine operation is not found to be an effective means of enhancing residual trapping. Instead, by modulating reservoir fluid pressure, boundary conditions of the reservoir exert a more significant impact on flow. Given the same well configuration and bottomhole pressure constraints, an open reservoir with lateral background flow allows 40% additional scCO2 injection compared to a compartmentalized system without background flow. However, background flow leads to a lower trapping efficiency – after 1000 years post-scCO2-injection, only 54% of the total injected scCO2 is immobilized as residual scCO2. This research suggests that a careful engineering design can contribute to significant CO2 storage at commercial scales while enhancing storage security. Site-specific multi-phase flow data should be measured for such a design, since for the study site, chase-brine operation is not effective when scCO2 relative permeability is low.

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Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability

Natural gas hydrates have been investigated as a potential resource for commercially producing gas since the 1990s. Based on the latest available data for the Shenhu area of the South China Sea (SH7), a practical two-dimensional model has been constructed to investigate the gas production potential and the distributions of different physical properties in alternating formations by selecting a proper perforated interval favouring borehole stability and gas production. The effects of overburden and underburden permeability on gas production are intensively discussed. The simulation results indicate that the initial hydrate dissociation mainly occurs among the upper gas hydrate bearing-sediments (GHBS) with a high permeability but that in the later period, it is mainly distributed among the bottom low permeability GHBS. In addition, an obvious hydrate re-formation can be observed in the middle GHBS, and the dilution effect in the bottom low permeability GHBS is stronger than that in the upper space with high permeability. A comparative study showed that the GHBS in the Shenhu area with only one permeable burden (overburden or underburden) is not the most promising target for depressurisation.

Evaluating the Risk of Casing Failure Caused by High-Density Perforation: A 3D Finite-Element-Method Study of Compaction-Induced Casing Deformation in a Deepwater Reservoir, Gulf of Mexico

Summary For a deviated well planned in a highly compressible deepwater reservoir in the Gulf of Mexico, a typical perforation strategy of 140° phasing with 16 shots/ft is unlikely to meet flux requirements at the anticipated production rate. Perforating the production casing twice to double the flow area is one option to avoid exceeding the maximum flux limit. But will the high-density perforations affect the casing strength enough to cause casing failure as the reservoir compacts, given the reservoir-operating limits? This cannot be assessed by using existing analytical models, by published numerical models, or from available empirical or experimental data. To evaluate the feasibility of using a double-perforation approach, a 3D finite-element method (FEM) was developed to determine the effect of the additional holes on casing failure. The model considers variations in both casing thickness and perforation pattern during expected wellbore and reservoir conditions. Both perforated and nonperforated casings were analyzed to compare casing-deformation characteristics and to determine the effect of the perforation on critical depletion pressures. The FEM model shows that casing deformation is not uniform, resulting from nonuniform strain loading across reservoir boundaries and nonuniform distribution of casing strength as a result of the perforation. For the nonperforated casing, the maximum strain is associated with bending near the reservoir boundaries. In contrast, the maximum distortion of the perforated casing is concentrated around the perforation holes at the ends of the perforated intervals. Allowing for a critical strain of 6% in the casing, the depletion limit would have to be reduced from 3,500 psi to 2,600 psi if the second set of perforations could be applied uniformly relative to the first set. A nonuniform distribution of the second set could further reduce the casing strength and lower the critical depletion pressure to 2,200 psi. Finally, the study also shows that increasing the casing thickness by 0.0625 in. would have almost no effect on casing deformation or the attendant reservoir-operating limit. The study quantifies how much casing strain to expect in the scenario described—and that is critical for evaluating the risk of casing failure in expensive deepwater wells. The results suggest that models similar to the one described here, in fact, offer a feasible way to assess casing deformation in highly compressible reservoirs in which high-density perforation may lead to casing failure.

Evaluation of fracability and screening of perforation interval for tight sandstone gas reservoir in western Sichuan Basin

The western Sichuan tight sandstone gas reservoir is characterized by low porosity, ultra-low permeability, and shale interbedding. The most effective way to exploit this formation would be large-scale hydraulic fracturing. Currently, however, no appropriate method exists for selecting fracturing candidates to maximize the scale of the complex hydraulic fracture system. Therefore, fracability should be evaluated when developing this type of reservoir. In this study, fundamental mechanical experiments are performed to determine the correlation between fracability and its influencing factors. Based on the experimental results, reservoir fracability is evaluated using a new model that integrates all of the related factors. Formations with high fracability are selected as hydraulic fracturing candidates, and a new method for selecting perforation intervals is proposed based on the determined reservoir fracability. As case studies, the appropriate perforation intervals are examined for two wells drilled in the western Sichuan Basin: vertical well XC32 and horizontal well HF-1.

Numerical simulation of produced water reinjection technology for water-soluble gas recovery

Water-soluble gas reservoir refers to those unconventional reservoirs composed of methane mostly, which dissolved in over-pressure and high-temperature groundwater. The Paleogene Wenchang and Enping Formations of the Huizhou Sag are major source rocks that generate significant quantities of gas and the sandstone reservoirs are varying from weakly overpressured to overpressured on the whole. According to the 3D geologic model using geostatistics method, the volume of water-soluble gas in the resource is about 1791.5 × 108 m3 and 2688.5 × 108 m3, 1.19 and 3.46 times of the conventional gas, respectively. The water-soluble gas is an unconventional resource with great potential, and can provide substantial gas source for conventional pools through degasification. In this paper, a new feasible technology is proposed for the development of water-soluble gas reservoirs. Produced water reinjection, when combined with water-soluble gas recovery, not only enhances the relatively gas production by maintaining reservoir pressure, but also contributes to the output of water treatment, especially under marine production conditions that faces the tough situation of the high cost and large number of water output. It has a significant meaning to alleviate the bottleneck problem of the resource shortage in Pearl River delta industrial base of China. A 3D injection–production model is developed using the TOUGH2/EOS7C program. Numerical results show that under the condition of constant bottom hole pressure 30 MPa, water injection can increase the plateau of the production period from 36.68 years to 70.53 years, and enhance the cumulative gas production effectively. Relative parameters are also analyzed, and the following conclusions can be drawn: producer–injector spacing and perforation intervals of producing well have considerable influences on the gas recovery, comparing with the rate of water-injection and perforation interval of injection well. In addition, it is necessary to find the optimal value of these parameters. In general, produced water reinjection is a potential choice for water-soluble gas recovery.

Fingerprinting Bacteria DNA in Crude Oil for Reservoir Characterization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166087, ’Application of New Fingerprinting of Bacteria DNA in Crude Oil for Reservoir Characterization - Part II,’ by A. Hayatdavoudi, N. Chegenizadeh, A. Chistoserdov, F. Boukadi, and R. Bajpai, University of Louisiana at Lafayette, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. In the early 1980s, while the authors of the original paper were reassessing some old gravel-pack sands from a well, some sludge was noticed in the samples. The sludge had plugged formation and the gravelpack pores. The permeability was so low that the owner of the oil property considered abandoning the well and consequently stopped all workover measures, concluding that there was no more oil left in the reservoir. The scenario suggested the existence of bacteria in the oil. In the current study, a novel, sensitive technique for bacterial deoxyribonucleic acid (DNA) fingerprinting is implemented. Introduction To find bacterially induced chemical changes in oil, the research team in the first of two complete papers (only the second part is summarized here) compared the chromatograms of six carefully sampled oils obtained from two wells. The oil samples were taken directly from two wellheads without disrupting the production from the naturally flowing wells. To obtain a representative oil sample from each perforation interval, three samples were taken at different time intervals approximately half an hour apart. The distance between tops of producing intervals was approximately 3,000 ft, and the wells were designated Well A and Well B. The operator believed the two wells produced oil from the same reservoir. Despite their effective use as a tool in oil fingerprinting, chromatographic fingerprints of oil samples raised more questions than the team expected. Actually, in view of the well-known fact that oil reservoirs provide a favorable ecosystem for the growth of bacteria colonies, the precise role of bacteria in modifying the oil chemical compounds or creating new compounds could not be ascertained by use of the chromatograms. The bacterial growth indigenous to the reservoir is attributable to the abundance of nutrient, whether inorganic, organic, or a combination of both. To survive, the bacteria must adapt to conditions in which they find themselves. The process of adaptability of bacteria to their surroundings (i.e., reservoirrock minerals and reservoir fluids as nutrients under reservoir conditions) can and will change rock petrophysical properties such as zeta potential; rock wettability; relative permeability; and permeability to water, oil, gas, or other flowing fluids. Generally, the bacteria in the water phase of petroleum reservoirs possess the ability to modify the surface chemistry of rock minerals and to extract or to concentrate metal and nonmetal ions. Molecular-biology techniques have only recently been used for exploring for oil reservoirs. Recent achievements in molecular biology have extended the understanding of the role of microbial transformation and maturation of petroleum compounds under certain pressure and temperature windows and have enhanced our ability to investigate the microbial communities in petroleum-impacted ecosystems. The analyses mostly have focused on identifying the diversity of microbial species present in or on the seeps, seabed, gas vents, and reservoir waters by use of microbial 16S rRNA, a ribosome (a ribonucleic acid found in all microorganisms since the beginning of life on the planet). To identify a microorganism, its 16S-rRNA sequence information is checked against the 16S-rRNA sequence data available in the GenBank database. 16S-rRNA gene information is available for microorganisms found in different parts of the world and great distances apart such as North Sea, South American, and Asian oil fields. By use of these free gene databases, microorganisms most closely related to those which have been found in oil or gas reservoirs can be identified accurately.

Methods Improve Stimulation Efficiency of Perforation Clusters in Completions

Technology Update Horizontal shale wells present the challenge of generating large, high-density fracture networks, reflecting the submicrodarcy permeability of the formations drilled by these wells. The goal is to create the largest fracture network volume to maximize ultimate recovery, because the fracture network volume in these wells has been shown to correlate strongly with the production level. However, as the network becomes too large for a given wellbore access point, the relative benefit of size diminishes. This is because of the low fracture conductivity, which creates large pressure drops within the network and makes it difficult to drain distant portions. And the effect is exacerbated by the inability to move water or liquid hydrocarbon through a large complex network (Mayerhofer et al. 2006). Thus, it is very important to create an optimal number of conductive transverse fractures or access points that intersect the wellbore. Today’s unconventional wells incorporate wellbore planning and completion designs that are based on the reservoir-specific characteristics needed for optimal drainage and field development. The key elements of the design and planning process must be carefully considered. They are well spacing, lateral length, the number of stages, the length of isolated stages, and the number of perforation clusters per stage. The strategies used are based in part on advancements in reservoir simulation, reservoir modeling, and production correlations from trial and error that stem from the initial work in various plays, except the relatively unique Barnett shale. Progress in Shale Completion Designs A good example of this progression toward more reservoir-specific completion designs was seen in the Haynesville shale. The play saw a rapid rampup in activity from 2009 to 2012 with peak completion activity occurring in mid-2011. By November 2011, it had reached its highest production level of 7.2 Bcf/D (EIA 2014). This dramatic rise in production was in part due to the optimization of completion and stimulation designs, particularly the reduction of the isolated length of each stage (plug-to-plug distance) and, thus, an increase in the number of stages per foot of lateral. The average daily gross perforated interval per stage (top perforation to bottom perforation) that Halliburton completed in the Haynesville and Bossier shales from 2010 to 2013 was analyzed. The data encompasses nearly 11,000 stages for more than 30 operators. It illustrates that many operators began to reduce their gross perforated interval per stage across the play by the middle of 2011. In July 2011, it was 272 ft and by mid-2012, it declined to 150 ft, falling at a relatively constant rate as operators increasingly went to a shorter isolated stage interval. This indicates closer stage spacing (plug to plug) or more stages per well, with lateral length remaining relatively constant. These trends continued into 2012 and a dramatic improvement was seen not only in the slope of the projected production decline curve, but also in the estimated ultimate recovery (EUR) for the wells being brought online.

Application of Well Temperature Logging in Coalbed Methane Well Fracture Effectiveness Evaluation

Mature oil well temperature logging technique was applied to coalbed methane wells in order to monitor the fracture height and guide the fracturing and drainage. The results show that, after fracture treatment, fracture height was bigger than that of perforated interval, and mainly extended upward. In the case of 11# coal seam in Taiyuan formation of Permian, Upper Palaeozoic, overlying K2 limestone were all cracked through, while in the case of 3# and 5# coal seam in Shanxi formation of Permian, Upper Palaeozoic, overlying sandstone section in some wells was cracked through. In the former case, the fracturing curve shows fracture pressure higher than 27MPa, pump off pressure higher than 20MPa, and high pressure dropping rate over 0.4MPa/min, while the fracture pressure lower than10MPa, pump off pressure lower than 5MPa and low pressure dropping rate that generally under 0.1MPa/min in the latter case. Fracture height is directly influenced by crustal stress of the rock cracked by fractures, and tends to become bigger with the increase of fracture pressure and pump off pressure. To achieve desired results after coalbed methane reservoir stimulation treatment, a restriction of fracture pressure during fracturing process is recommended to control fracture height.

Research of Interlayer Interference and Development Strategy of Multilayer Commingled Production Gas Reservoir

Sebei gas field is featured with the characteristics of the shallow-buried gas reservoir, long gas containing well section, multilayer gas reservoirs beds, the complicated gas/water contact distribution, the water produced obviously, sands produced frequently from the gas wells and the multi-layers gas reservoir extracted unbalancedly in the developing process. For these reasons, the paper proposed the method that interlayer interference coefficients are defined with statistical function. Combined with the data of the sand-layers profile test, the effects of the numbers of different sand-lays, the perforated thickness, the perforated interval length and permeability contrast on the interlayer interference are evaluated and these permeability parameters are optimized.

Water Coning Simulation Mode in Fractured Gas Reservoir with Bottom Water

There are two percolation models, horizontal radial flow above perforation interval, and semispherical centripetal flow below perforation interval. Based on this models and the theory of percolation flow through porous media, a study on prediction of water breakthrough time in fractured gas reservoir with bottom water is presented. Through mathematical calculations, a formula to determine the time of water breakthrough in fractured gas reservoir with bottom water wells is derived. Case study indicates that water breakthrough time decreases with the fracture development index. With increase of perforated degree, water breakthrough time increase first and then decreased after a critical value, which could be considered as optimum perforation degree. If the perforated degree is fixed, the water breakthrough time is directly proportional to the thickness of the gas reservoir and inversely proportional to the gas production rate.