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Abstract Production from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000. A total of 63 wells have been tested with well site compression; there are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional wells highlighted by the Moving Domain study. Compressors were installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost, take advantage of higher gas prices at the time, and gather data for proper design and sizing of the compressors. Following studies were carried out as part of the project:Compare the response of wells in high-pressure area and low-pressure areas of the reservoir to wellhead compression. Feasibility study investigated the field wide compression by use of Central Compression System. This was followed by a study to determine the economics of well site compression versus central compression system. Financial study was carried out to determine the economics of leasing versus purchasing the well site compressors. The results and conclusion of project were:Reservoir technologies like Moving Domain study helped in candidate selection. The compressor project has been a success with an average initial uplift of 102 MCFD per well for 52 successful Judkins wells tested. Although the gas production increased significantly the decline rate has also increased indicating that we have accelerated gas production with some addition in reserves. Central Compression system with an estimated project cost of $12 million was found uneconomical. Individual well site compression was more economical method for gas production optimization. A total of $850,000 have been spent in three phases over 3 years. Several operational improvements evolved which decreased downtime and cost of maintenance and enhanced the profitability of these installations. All these have been listed under the lessons learned part of the paper. Introduction Waddell Ranch Project is located in the Permian Basin in Crane County, Texas. It started production in the early 1930's and covers more than 1400 active wells in an area about 80,000 acres. The project includes 47 fields, which have produced over 400 million bbl of oil and 1.1 Tcf of gas. Six major fields account for 90% of the production from 12 zones ranging in depth from 2,800 to 10,600 feet. Most prolific of the zones are the Grayburg and San Andres that produce from depths between 2,800 feet and 3,400 feet. CMC / IPM's performance as the operator has been excellent as illustrated by the project's exploration, exploitation, production, safety and maintenance records. Fig 1 below shows the gross oil and gas production from 1980 through 2003.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
Abstract With a 217 STB/MMSCF liquid-gas ratio (LGR) Sarvak reservoir of CARBONATE field in Iran is one of the richest gas condensate reservoirs in the world. Due to asphaltene precipitation during well shut-in, it is impossible to acquire static pressure data for the reservoir. Since the reservoir pressure is of the main reservoir parameters for performance prediction, material balance calculations was performed based on volumetric and PVT data to determine current reservoir pressure. Furthermore the retrograde condensate deposition (liquid drop-out) is also calculated with the introduction of new parameter of Liquid-Fluid ratio (LFR). The curve of P/z (the ratio of pressure and gas deviation factor) versus cumulative gas production is conventionally utilized to predict the gas reservoir performance. This method is used for gas condensate reservoirs by replacing gas z-factor with two-phase z-factor (zT). Since reservoir pressure data are not available a direct usage of the above method for CARBONATE-Sarvak reservoir is impossible. As such the experimental data of Constant Volume Depletion (CVD) experiment have been used that simulate the gas condensate fluid behavior. The experimental data are simulated using the PVT simulator of Winprop and tuned to Peng-Robinson EOS to provide non-available parameters and to check the validity of the data. Gas deviation factor at the dew point (zd) was determined as 1.2433 based on which the two-phase z-factor was calculated for different pressures below the dew point pressure. Backward calculation was performed to correct the available experimental data of produced gas percentage to reservoir conditions. The percentage of gas produced to reach the dew point was determined as 3.3029 percent of the Gas Initially In Place (GIIP). Utilizing the GIIP of 620 MMMSCF concluded from volumetric calculations the reservoir will reach the dew point after 20.48MMMSCF of gas production. It is estimated that current reservoir pressure after cumulative gas production (Gp) of 60 MMMSCF would be 5819 Psia. Furthermore the retrograde liquid deposition of the reservoir is determined to be 35.31 MMSTB through the plot of liquid-Feed Ratio (LFR) versus Gp/G. 1-Introduction With a 217 STB/MMSCF liquid-gas ratio (LGR) Sarvak reservoir of CARBONATE field-located in south west of Iran- is one of the richest gas condensate reservoirs in the world. Gas and condensate production from this reservoir has been started on Sep, 1994 with 16 MMScf/Day of dry gas and 500 STB/day of condensate. In spite of almost long production history it was not possible to acquire static pressure data for the reservoir due to asphaltene precipitation during well shut-in. Since the reservoir pressure is of the main reservoir parameters required for performance prediction, material balance is performed in this study based on volumetric calculation and PVT data analysis to determine the current reservoir pressure. Furthermore the reservoir performance including the reservoir pressure and retrograde liquid deposition is predicted. 2-Work procedure The main goal of this study is current reservoir pressure determination, reservoir performance prediction, and liquid deposition estimation. Utilizing the curve of pressure to z-factor ratio (P/z) versus cumulative gas production (Gp) is the conventional method to predict the gas reservoir performance. To apply this method for gas condensate reservoirs the gas z-factor should be replaced by two-phase z-factor (zT) calculated for reservoir pressures lower than the dew-point pressure[1,2,3]. In case of Sarvak reservoir of CARBONATE filed a direct usage of the above method is not possible due to lack of static pressure data.
- Asia > Middle East > Iran (0.44)
- North America > Canada (0.28)
Abstract Gas recycling experiments were conducted on a gas condensate sample in a fractured model. Experimental Model was then numerically simulated with compositional simulator. The objectives were to investigate effects of gas recycling on condensate recovery from a naturally fractured reservoir under complete pressure maintenance process. In laboratory scale we could accurately analyse behavior of in-place and injected gas in fracture and matrix blocks and understand how the production mechanisms affect ultimate recovery in this reservoir model. In reservoir scale, due to high heterogeneity and lack of required data such an accurate investigation is impossible. In the simulated model after history matching of cumulative gas and condensate production and composition variation history of produced gas, some sensitivity analysis were performed. Simulation results show that gas recycling increases liquid recovery more than 2.5 times for the reservoir if the fracture model behaves as dual permeability fractured reservoir. If model behavior supposed to be dual porosity, condensate recovery decreases dramatically due to early break through of injected gas via fractures. Cyclic injection-production and decreasing the production rate are the factors directing the process to higher ultimate recoveries. Nitrogen injection effect has also been established showing less recovery than dry gas injection case. Finally, lacks of data for a complete compositional simulation of such models are mentioned. If the data be prepared prior to performing the experiment, results could be up-scaled to the reservoir with higher degree of assurance. Introduction Gas recycling in gas condensate reservoirs has been recommended for several years as an optimum production scenario of increasing condensate recovery. For fractured media, the process is more complex due to early break through of injected gas in fracture network, and activation of production mechanisms like diffusion and gravity drainage of condensates. Experimental gas recycling is most often used to predict recycling performance of the reservoir. With a complete rock and fluid analysis before starting the experiment, laboratory results can be up-scaled to design the recycling procedure in the reservoir. By preparing most similarity between laboratory model and reservoir conditions, probable errors would be minimized during up-scaling. Laboratory gas recycling experiments are time and cost consuming; also in reservoir scale we face high heterogeneity and large scales and couldn't perform accurate investigation on recycling process. Numerical simulation of laboratory models prepares accurate investigation of recycling performance to select best conditions of pressure maintenance process for a reservoir. Most important factors are the injection and production gas rates, composition of gas to be injected, and when is the best time to start and finish the recycling to achieve most economic conditions. Gas condensate behavior is highly sensitive to the heavy fraction composition of the fluid; so the most probable errors occur in fluid sampling and phase behavior modeling. Reducing deviations as will be discussed would yield in accurate up- scaling of the experiment to the reservoir. Experimental setup and procedure Six sandstone core plugs stacked vertically in a core-holder. Horizontal and vertical spaces were considered between cores and core holder as horizontal and vertical fractures (Fig.1). Average porosity of matrix was 21% and average permeability of matrix and fracture were measured to be 409 md and 550 darcy respectively. (See properties of rock samples in table 1.) Gas and liquid samples were taken from surface separators and recombined with liquid gas ratio of 20 bbl/MMScf to represent the reservoir fluid. Compositions of reservoir gas and dry gas are shown in tables 2, 3 respectively.
- North America > United States (0.29)
- North America > Canada (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
Abstract Sour gas reservoirs with high content of sulfur are distributed widely around the world. Solid elemental sulfur which dissolves in the gas phase originally in the reservoir, may deposit when the thermodynamic conditions of the temperature, pressure or composition changes in the process of production. Deposition of solid elemental sulfur may block the pores in the formation and significantly affect the gas deliverability. In this paper, sulfur deposition mechanism is analyzed in the reservoirs. Based on the characteristics of sulfur deposition in the formation, a corrected function is introduced to modify the gas flow. Then, an evaluation method of the effect of sulfur deposition on gas deliverability is presented. For a practical sour gas reservoir, the gas deliverability considering sulfur deposition in formation is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the physical parameters in the formation on which the gas well is located. Introduction Because of the high content of sulfur, especially when the concentration of H2S is high in the reservoir fluid, the critical production technology is required. Reduction of pressure and temperature of reservoir which reduces the solubility of sulfur in sour gas will cause sulfur to deposit in the reservoir. Deposition of sulfur within reservoir rocks can impair porosity and permeability and results in the decline in gas productivity and thus affects economic feasibility negatively. Many of the operational and reservoir parameters influence sulfur deposition. A theoretical research was studied by Kuo[2] on investigating the effect of the deposition of immobile elemental sulfur from a homogeneous reservoir. Sulfur deposition in the formation was attributed to the decline in production from a well producing from a dry, sour (16% H2S) gas pool operated by Shell Canada Limited located in the Waterton gas field of south-west Alberta, Canada. Sour gas reservoirs with large amount of hydrogen sulfide, 7.13%-10.49% (102.07โ196.57g/m3), Sulfur are found and developed in recent years in China, such as gas reservoir of Fei Xian Guan, Luo Jia Zai, located in Sichuan province. The distribution of sulfur in a core is illustrated in Fig.1.[1] In this paper, the focus is on the prediction of deposition of sulfur and reduction of gas productivity in order to assess the impact of sulfur deposition on inflow performance.
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract To exploit the substantial tight-gas resources worldwide, hydraulic fracturing is, for many cases, economically a viable option. However, despite the state of the art techniques such as multiple fracturing of horizontal wellbores, the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality, strong stress dependency in permeability, hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one, related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics, was rarely taken into account before and is the subject of the current paper. For this purpose, an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator, capturing the yield stress of common polymer gel. The model is applied to typical cleanup scenarios. Using the model, it can be shown that the residing, non-recoverable gel (typically 50%) decreases the fracture conductivity and, hence, the production potential of a fractured gas well. This coincides with experiences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fracture, gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in analytical studies, there is no sharp interface between the residual gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of fracture cleanup processes and, hence, an improved understanding of formation damage processes in fractured wells. Furthermore, the model enables the design of more successful fracture treatments in tight-gas reservoirs. Introduction Evaluation of postfracture performance has been the subject of extensive investigations over the past decades. For hydraulically fractured gas wells, a number of potential damage mechanisms were identified, such as hydraulic damage caused by invading fluids during the treatment and damage due to the stresses exerted on the fracture face. In addition, damage to proppant pack, reducing the conductivity and the associated non-Darcy flow effects which cause additional inertial pressure drops, were also attributed as causes of possible productivity impairment. However, these effects are not solely responsible for potential productivity impairment in tight-gas reservoirs. Many tight-gas wells do not respond to hydraulic fracturing as expected. Following the fracturing treatment, a typical tight-gas well achieves its maximum gas rate within a few days after stimulation and then experiences a rapid production decline. Some tight-gas wells, in contrast, do not show such obvious production peaks but instead sustain a flat production profile or exhibit a slowly increasing production rate for several weeks or months.[1] A major potential reason for this behaviour given in previous studies was the fracturing fluid. Commonly, cross-linked polymers facilitate hydraulic fracturing treatments, the intent being that the polymer will be recovered once production is initiated. In the field, only a fraction of the injected polymer can be produced during the cleanup process, typically up to 50%. Slugs of unbroken residuals were reported during the post-fracture production and indicate the existence of gel residues inside the fracture after the cleanup process. The incomplete degradation of the polymers in the fracturing fluid results in productivity impairments due to formation and proppant pack permeability reduction. Fracturing fluid issues are suspected to contribute to the discrepancy of effective and propped fracture half-lengths with fracture conductivities commonly much lower than anticipated.
Field Application of Combined Kinetic Hydrate and Corrosion Inhibitors in the Southern North Sea: Case Histories
MacDonald, Andrew (Clariant Oil Services) | Petrie, Mark (Clariant Oil Services) | Wylde, Jonathan James (Clariant Oil Services) | Chalmers, Alison (Clariant Oil Services) | Arjmandi, M. (Clariant Oil Serivces)
Abstract This paper details three field applications of combined low dose hydrate (LDHI) and corrosion inhibitor (CI) chemicals in different assets in the Southern North Sea (UKCS) gas producing area. The design and application philosophy is discussed as well as the criteria necessary to manage a safe and efficient chemical transition. The three fields all displayed mid-level degrees of sub-cooling (4 - 8 ยฐC) with operating pressures up to 70 bar with variable water breakthrough. Corrosion was severe in some cases with over 700 ppm of H2S production combined with 1.1 mol % CO2 in the produced gas. The paper goes onto describe the cost benefits of such applications including increased equipment efficiency, logistical savings of single chemical deployment and lower maintenance costs. In addition improved hydrate and corrosion control was achieved over the incumbent chemical. This approach achieved cost savings, including a saving of $3 million in the first year of application on one of the fields. Environmental benefits have also been realised with reduced chemical usage and discharge and improved environmental profile of the combined products when compared to the originally selected single application chemicals. Introduction Hydrates Hydrates were first described in 1810 by Sir Humphrey Davy[1] and were reported as forming when gas (predominantly methane) and water combine under suitable temperatures and pressures. Although snow like in appearance, they can form at temperatures much higher than the freezing point of water. Hydrates are actually cage-like structures called clathrates and have two common forms - Type I and II.[2] Hydrates typically form with low molecular gas compounds such as methane, ethane and propane. Other species such as nitrogen, carbon dioxide and hydrogen sulphide can also promote hydrate formation. Hammerschmidt reported the formation of hydrates in gas pipelines in 1934.[3] Hydrates are known to plug flowlines, pipelines, valves and other equipment whilst removing hydrate blockages is a dangerous task potentially resulting in a hydrate missile. This can be caused by the rapid dissociation of a hydrate at the outer edges combined with the pressure build up caused by the blockage. A number of methods exist for controlling hydrates but the most common method is the use of thermodynamic inhibitors, such as methanol or glycol (monoethylene glycol, MEG). These treatments are effective by lowering the freezing point of an aqueous solution, similar to anti-freeze in a car engine. Methanol is a low cost chemical which can be recovered from the process steam but increases risk to the environment and in handling. MEG is also recoverable but requires higher injection rates than methanol and viscosity can be a limiting factor for injection via long sub sea tie-backs. MEG regeneration can also be subject to salt fouling. Triethylene glycol (TEG) can be used to de-water wet gas and as such remove a required component of hydrates. In order to overcome the issue of supply of large volume of chemical, regeneration, handling and environmental issues, a new generation of low dose hydrate inhibitors (LDHI) were developed. Two types of LDHI presently exist; kinetic hydrate inhibitors (KHI) and anti-agglomerates (AA). The particular type selected for hydrate control is dependent on a number of factors including the severity of the hydrate problem, the water cut in the pipeline, the amount of hydrocarbon present and the period of time hydrate control is required.[4] KHI's work by delaying initial hydrate nucleation. The mechanism of inhibition does not alter the thermodynamics of hydrate formation, but is a surface adsorption phenomena of the inhibitor such that growth is retarded, thus delaying hydrate formation for a given time, known as induction time. AA's differ from kinetic inhibitors in that they allow a certain amount of growth of gas hydrate but then act to suppress the continued propagation and agglomeration by dispersing the hydrates in the oil or condensate phase. With AA's the brine:hydrocarbon fluids ratio and composition of these fluids are more influential on performance. Both KHI's and AA's are referred to as LDHI's since much lower treatment rates are required than compared to thermodynamic inhibitors.
- Europe > North Sea (1.00)
- Europe > United Kingdom > North Sea (0.61)
- Europe > Norway > North Sea (0.61)
- (2 more...)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract Collection and analysis of gas/condensate fluid samples present considerable challenges. That is because downhole sampling of a gas/condensate fluid, unlike its oil counterpart, does not guarantee retrieval of single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality, the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older generation formation testers, those prior to 1990, although yielding comparable results, had larger error bars owing to system limitations in repeatability of both pressure and depth measurements. We developed a yield-temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multi-reservoir samples, which is particularly useful when rapid assessment is needed over large regions. Introduction The presence of a compositional gradient in reservoirs containing hydrocarbon columns has long been recognized since Sage and Lacey (1939) published their seminal work. Segregation of asphaltenes causes compositional grading in oil (20โ30 ยบAPI) columns. In contrast, compositional grading in light-hydrocarbon (> 35 ยบAPI) columns occurs for near-critical fluids or, more appropriately, for fluids close to the spinodal curve (Lira-Galeana 1992). Equilibrium between gravitational and chemical forces of various hydrocarbon components results in a variable saturation pressure in a fluid column (Schulte 1980; Riemens et al. 1988; Wheaton, 1991). According to Hirschberg (1988), the time to reach such equilibrium (10 million to 1 billion years) is comparable to the geologic time of a typical reservoir. A number of authors have reported field experiences with compositional grading in gas/condensate reservoirs (Creek and Schrader 1985; Smith et al. 2000; Ghorayeb et al. 2003). Ordinarily, the equilibrium approach appears to explain gradients observed in the field. In reality, however, heat flux can potentially prevent attaining true equilibrium in a hydrocarbon column owing to temperature gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier and Whitson 2001; Ghorayeb and Firoozabadi 2000; Firoozabadi 1999). Irreversible thermodynamics appears to explain compositional grading in most systems. In this study, we will assume that thermal diffusion does not play a dominant role in distributing hydrocarbon components in the fluid columns studied. As discussed, depth-dependent fluid property variation has been shown to occur by discerning PVT properties (Hanafy and Mahgoub 2005; Smith et al. 2004; Montel et al. 2003). However, direct comparison of independent measurements contributing to fluid gradients has been rare. The principal objective of this study is to compare fluid gradients from three different sources to seek consistency, en route to establishing liquid content in gas/condensate systems. These independent sources include (1) EOS-model-derived compositional grading, (2) spot pressures measured by wireline formation testers, and (3) wellbore static gradient from a dynamically calibrated drillstem test (DST) data. Case Studies Spot pressures and the attendant fluid gradients derived from wireline formation testers (FT) are invaluable to all, earth scientists and engineers alike. While the ability of formation testers to reveal fluid gradients is seldom questioned, we probe whether fluid gradients of sufficient accuracy can be discerned to yield reliable liquid content in gas-condensate systems. In this study, besides FT we examined two other sources of fluid gradient information; compositional gradients based on EOS models and the static-fluid gradient obtained from a calibrated wellbore flow model. The compositional gradient is obtained after tuning an EOS model and the wellbore model is calibrated with DST flowing pressures and temperatures at both bottomhole and wellhead. Note that all the necessary ingredients, such as surface rates of both phases, pressures and temperatures at both wellhead and sandface, are available from a DST.
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Maturin Basin > Orocual Field > San Juan Formation (0.99)
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Maturin Basin > Orocual Field > Las Piedras Formation (0.99)
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Maturin Basin > Orocual Field > Carapita Formation (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > Birba Field (0.99)
Abstract Vibration of drillstring was found responsible for the severe damage and premature failure of drillstrings during drilling the gas-bearing igneous formations in the Songliao Basin, China. The vibration significantly shortened the life of drillstrings and had a great impact on drilling performance in the area. The objective of this study was to identify the key factors affecting drillstring vibration and develop a control-mechanism to reduce the failure rate of drillstring. This study investigated the combined effect of axial and torsional vibrations on the damage of drillstring. A computerized model was built to simulate loads from axial and torsional vibrations. An analytical method for predicting the fatigue life of drillstring was developed. The method uses the output from the computerized model. Engineering charts were also generated for typical drilling conditions. These charts have been adapted in a Drillstring Damage Control Program implemented in the Songliao Basin, China. Introduction Natural gas was found at the beginning of this century in the igneous formations in the Songliao Basin, China. With high contents of quartz and other dense minerals, these formations are very hard and abrasive. They are also heterogeneous with natural fractures and vugs. Types of minerals in the formations vary with depth. When these formations were drilled, severe axial and torsional vibrations of drillstring were observed at surface. Premature failures of drillstring and drill bits were very common in the area. This study was initiated to identify the key factors affecting drillstring vibration and develop a control-mechanism to reduce failure rate of drillstring to an acceptable level. It has long been recognized that vibration of drillstring is detrimental to the surface and downhole equipment in well drilling process (Li and feng, 1990). The vibrations cause premature wear and fatigue failure of drillstring itself. Combination of axial and torsional vibrations can significantly shorten the life of drillstring and have a great impact on drilling economics in harsh drilling areas. Guo et al. (1994) presented a mathematical model coupling transverse and torsional vibrations while axial vibration was neglected. Quantitative analyses of the effects of axial-torsional-combined vibration on the fatigue life of drillstring have been very limited in the petroleum literature. Existing mathematical models that consider axial vibration only are not adequate for predicting fatigue life of drillstrings in hash drilling conditions. This study focused on two aspects:building a computer simulator to predict the maximum axial and torsional stresses; and developing a method to predict the fatigue life of drillstring using the results from the simulator. After completion of these works, engineering charts were generated for typical drilling conditions, which have been utilized in an implemented Drillstring Damage Control Program in the Songliao Basin, China. A significant improvement of drilling performance in the area is expected. Mathematical Model Drillstrings vibrate in three modes: axial, torsional and transversal vibrations. Usually one of them dominates in a given system. Combination of two or three of them can play important roles in harsh conditions. At present, some mathematical models are available for analyzing axial, torsional, and transversal vibrations of drillstring separately, but none of them reflects the actual downhole conditions in drilling operations. It was believed that a more relevant model should be developed to consider the combined effect of at least two vibration modes. The mathematical model described in this paper was formulated by rigorously coupling the axial and torsional vibration components. Coupling of Axial and Torsional Vibrations Consider roller bits that are used for drilling hard formations. Because the teeth of drill bit contact hole bottom alternately, an axial vibration in the drillstring is generated by the cyclic force from the hole bottom (Figure 1). It is also expected that the torque on the drill bit will be cyclic and it will generate torsional vibration in the drillstring (Figure 2).
- Geology > Geological Subdiscipline > Geomechanics (0.97)
- Geology > Mineral (0.74)
- Well Drilling > Drillstring Design > Drillstring dynamics (1.00)
- Well Drilling > Drilling Equipment (1.00)
Abstract This paper presents a simple, but accurate, computer method for predicting the performance of multiple gas wells in complex reservoir scenarios. Real life gas reservoir characterization and forecasting can be accomplished with the substantial reduction of effort when compared to numerical simulation and a substantial increase in accuracy when compared to traditional decline methods. Conventional analytical methods in many cases are highly unsuitable for new field development, in-fill drilling, or long-term production planning. Numerical simulation methods often require impractical pre-processing or computational time. With the method presented in this paper, production profiles can be generated for arbitrary shaped gas reservoirs with multiple wells. The model presented overcomes many limitations of traditional methods, and extends analytical modeling into multiple well scenarios with interference effects, arbitrary reservoir shapes, and perhaps even varying rock properties. Introduction: General History & Motiviation Modeling of petroleum reservoirs and its application to pressure and production analysis have been studied for years. Publications by Hurst (1981), Lee (1982), Streltsova (1988), Stanislav and Kabir (1990), Raghavan (1993), Mattox and Dalton (1990), and Settari and Aziz (1979) cover the important concepts of both numerical and analytical models. Others such as Muskat (1937) and Van Everdingen and Hurst (1949) outline more specific solutions for constant rate drawdown in infinite reservoirs, while Matthews, Brons, and Hazerbroek (1954) and Dietz (1965) investigated solutions for a single well in a bounded reservoir. Agarwal, Al-Hussainy and Ramey (1970) included wellbore storage and skin effects into the wellbore boundary conditions. Odeh and Jones (1965) described the pressure changes due to variable rate production. The list of contributors to the science and technology of reservoir modeling is extensive - and can generally be classified into either analytical or numerical. With respect to analytical methods, there are only a few conventional methods for solving the diffusivity equation. These include separation of variables, eigenfunction expansion, similarity transform, Laplace Transform, Fourier Transform, and Green's functions. However, due to certain restrictions in solving such problems, analytic methods are generally only amendable to simple geometric shapes. Generally, this problem can be alleviated by superposition (assuming linear differential operators). The shortcomings of analytical methods are also alleviated by numerical schemes such as the Finite Element Method (FEM) and Finite Difference Method (FDM) which have a greater flexibility in solving complex problems - however, this is generally at the expense of time and computational power. For example, with FEM, users must spend significant amounts of time generating appropriate grid orientation, and ensuring that accuracy is not compromised due to numerical dispersion etc. A literature review suggested that a good comparison of FDM and FEM is given by Russell and Wheeler. Therefore, a technique which has the accuracy of the analytical methods and preserves the versatility of the numerical techniques to solve complex reservoir problems is highly desirable. As a result, the Boundary Element Method (BEM) has become popular, and has been heavily studied by Kikani,[1] Archer,[2] and Pecher[3] to name a few. Others such as Larsen attempted to improve the use of superposition to handle more complicated reservoir geometry. In all cases, significant computation effort was required for success - either in calculating image well locations or evaluating complex (and sometimes undefined) integrals. Lin,[4] Caudle,[5] Jankovic,[6] and Haitjema[7] made use of approximate forms of superposition to handle more sophisticated aspects of multi-well interaction - however, most studies were limited to steady state applications for pressure contour and streamline mapping.
- North America > Canada > Alberta (0.28)
- North America > United States > Texas (0.28)
Abstract This paper illustrates a practical systematic approach to determine the reservoir flow characteristics and reserves for both conventional and unconventional gas wells. Currently, there is an industry assortment of production analysis methods ranging from exponential decline and typecurve matching to rate-pressure normalization techniques and detailed production history matching. Through real life cases studies it will be shown that it is possible that a simpler reservoir model, such as a single well completed in the center of a circular reservoir, could be used to represent far more complex reservoirs, and still provide some representative reservoir characterization, as well as accurate reserves analysis and production forecasting. As a result, it possible that engineers and the like can avoid some of the more labor intensive production data analysis (PDA) techniques, and use more a methodology similar in operation to traditional decline. Case studies and experience presented in this paper will demonstrate that a simple approach of production analysis methods will allow for a) proper identification of flow regimes, b) reliable evaluation of drainage area and OGIP, and c) the prediction of future deliverability and depletion. Case studies will also show that up-scaled and aggregate reservoir properties can provide a real measure of gas well deliverability (therefore a simpler, time-efficient model analysis can be used). Data uncertainty, unconventional gas (i.e. coal bed methane, tight gas, shale gas), stimulation appraisal, and other factors will be discussed in the context of the case studies. Introduction The most common reason for analyzing gas production data is to estimate reserves and future production of gas wells. In forecasting, a variety of methodologies exist ranging from simple decline to complex numerical simulation. In many instances, even pressure transient analysis (PTA) is used to form the basis of a forecast model. However, usually due to time limitations, only empirical methods such volumetrics, and conventional decline analysis are used. As a result, there is challenge is to get the most out of information embedded in production and flowing pressure data to provide improved mechanistic predictions of future gas well performance. Again, sophisticated methods, such as numerical simulation, have been available for decades and may provide the answers that industry needs. Although their predictive capabilities are proven, the accessibility (i.e. ease of use) of these methods is the issue. Of course, if time permits, all other techniques should be used. Background Early attempts to linearize and extrapolate production history were limited. Future production could be estimated if one assumed that the production trend remained linear and constant for the remaining life of the well (i.e. stable fluid properties, constant flowing bottom-hole pressure (BHP) etc.). The difficulty of applying this type of decline analysis for gas cases is that these assumptions are severely restrictive and are therefore frequently violated. Again, given business time constraints, the aforementioned methods are the norm for industry. In order to address the deficiency of standard decline analysis, typecurve analysis has been developed over many years. Typecurves are plots of theoretical solutions to flow equations (usually constant flow rate, or constant BHP) and can be generated for any kind of reservoir model for which a solution describing the flow behavior is available. Typecurve analysis theoretically allows one to estimate gas-in-place and gas reserves at some abandonment condition, as well as flowing characteristics of individual wells (i.e. permeability and skin). A common set of decline typecurves are those presented by Fetkovich (1980). Although more reservoir information is learned using Fetkovitch typecurves, they were still limited by the assumption of constant BHP, and constant fluid properties. Carter (1985) offered improved accuracy by using a plotting function that included the changes in fluid properties with average pressure. These curves were still limited to the assumption of constant flowing pressure. Carter's approach was similar to the pseudo-time function introduced by Agarwal (1979) in which the focus was to account for pressure dependant fluid properties in the near wellbore region during a flow and buildup analysis. Fraim and Wattenbarger (1987) also introduced a pseudo-time function to transfer a gas system into a single phase liquid system.
- Information Technology > Data Science (0.53)
- Information Technology > Modeling & Simulation (0.48)