Refinement of the conceptual model and algorithms to the development of hydrocarbon deposits based on fractal ideas about the nature of their geological structure

Summary The purpose of this work is to study the process of destruction of a productive reservoir and removal of sand to determine the permissible depression on the formation during the operation of wells in gas fields. On the basis of laboratory core studies modeled the process of reducing pore pressure and fracture of the core, the influence of processes of destruction on the change of reservoir properties of productive formation. The research is based on geomechanical analysis of changes in filtration and capacitance properties. The analysis is reduced to comparing the mechanical properties and strength of rocks with the stresses that occur during the development of hydrocarbon deposits. When the value of the stress acting on the productive layer is lower than the strength, elastic deformations of the rock dominate, and the layer is deformed slightly. If changes in the stress acting on the rock during development (reduction of reservoir pressure) exceed some acceptable values, then irreversible plastic deformations begin in the rock.

Thermal processes application in carbonate heavy oil reservoir is less successful than sandstone reservoir due to its feature that is naturally fractured and oil-wet condition. The enhanced oil recovery by steam drive in carbonate reservoir is often low because the steam easily bypasses oil which is locked in low permeability matrix. In addition, the recovery mechanism by steam injection is not well understood so far. The research from last decade showed that recovery mechanism is dominated by complicated interactions between oil/brine/rock and mineral heterogeneity. Imbibition and drainage may dominate the heavy oil recovery from fractured carbonate reservoirs when the steam is injected. This work presents an experimental study that was designed to characterize the recovery mechanism of steam injection in heavy oil carbonate reservoir by simulating the reservoir conditions. Several reservoir rock samples with a length of 3 inches and a diameter of 1.5 inches were used for both free and forced imbibitions at elevated temperatures. The crude oil from the same formation has an API gravity of 14 and a viscosity of 5624 cp at room temperature was used as oil phase. The water phase was either synthetic formation brine or 5000 ppm NaCl brine. A high resolution CT scan imaging technology was used for screening core candidates and cutting the core plugs to avoid a significant difference in core properties which may affect recovery mechanism. This study revealed that the oil recovery from carbonate reservoir by steam flooding is mainly dominated by imbibition, viscosity reduction, and in-situ steam generation inside the core. The increase in imbibition oil recovery is strongly dependent on the interaction between the oil/brine/rock which in turn affects the wettability rock. Effluent brine chemistry analysis verified that carbonate dissolution is associated at a temperature above 300°F, which may result in wettability alteration toward water-wetness. The oil recovery by free imbibition increased from around 10% OOIP to 50% OOIP as the temperature is increased from 100 to 400°F. If the pore pressure is suddenly reduced from 350 psi to room atmosphere pressure at 400°F (in-situ flashing process), the oil recovery can be further increased to 60–70% OOIP due to a significant amount of steam is generated in-situ. Correspondingly, the rock compaction is observed during the flashing process. The measured rock compaction is less than 4% of the total pore spaces. Compared with free imbibition, forced imbibition at low temperature gives higher oil recovery at low temperature, but does not show significant increase in oil recovery at high temperature.

The recent downturn in the industry has led to a focus on maximizing economic recovery and low-frequency seismic sounding (LFS) technology has the potential to delineate oil and gas reservoirs to derisk drilling decisions and shorten the appraisal and development timeframe. The change in the low-frequency range of natural microseismic background noise is due to the mechanics of fluid saturated, fractured and porous media, with oil and gas reservoirs having a high-velocity dispersion and attenuation at low frequencies. Here, we demonstrate the offshore deployment, acquisition and applicability of LFS to delineate hydrocarbon deposits in the North Sea. The spectra of the dry and oil-bearing sections of the surveyed area is observed in the frequency range of 0.6–1.9 Hz, while noise interference in the form of Scholte waves is also observed in the low-frequency range of 2Hz. We developed new filtering procedures to remove interference and exclusively select vertically directed P waves from the recorded signal. The result is a map of correlation coefficients which characterize the absence and presence of hydrocarbons as a probability map of hydrocarbon. The offshore trial has confirmed the application of the LFS technology highlighting areas that can be improved to deliver optimal results.

The almost complete depletion of easily recoverable oil reserves and intensive development of reserves with complex geological structures characterize the development of oil fields today. Due to the non-standard geological structure of such reservoirs, operators face multiple challenges that do not appear with the production of easily recoverable oil. A vivid example is oil field K, which contains low-viscosity oil and has a well-permeable terrigenous pore reservoir. Initial data obtained during exploratory drilling and trial production allowed optimistic forecasts of achieving an oil recovery factor (ORF) of 0.364. However, features of the geological structure hindered the achievement of this recovery target. This paper studies explore potential strategies for increasing oil recovery in the AB 1-2 area of oil field K. The aim of this paper is to identify reasons for the low oil recovery at oil field K and to develop recommendations for methods, which could enhance recovery and increase the oil recovery factor. The authors created synthetic hydrodynamic model of the AB1-2 oil object. They also performed multivariate calculations to analyze the structure of oil saturation and clarify the causes of low oil recovery. The authors reviewed six development strategies for the AB 1-2 object model: traditional water flooding, cyclic water flooding with injection wells, cyclic water flooding with injection and production wells, and polymer flooding. The oil recovery factor values obtained in these scenarios ranged from 0,238 to 0,265. Based on the results of this study, the authors recommend to use a combination of cyclic and polymer flooding.

Abstract:The uplift is a positive structural unit of the crust It is an important window for continental dynamics owing to its abundant structural phenomena, such as fault, fold, unconformity and denudation of strata. Meanwhile, it is the very place to store important minerals like oil, natural gas, coal and uranium. Giant and large‐scale oil and gas fields in China, such as the Daqing Oilfield, Lunnan‐Tahe Oilfield, Penglai 19–3 Oilfield, Puguang Gas Field and Jingbian Gas Field, are developed mainly on uplifts. Therefore, it is the main target both for oil and gas exploration and for geological study. The uplift can be either a basement uplift, or one developed only in the sedimentary cover. Extension, compression and wrench or their combined forces may give rise to uplifts. The development process of uplifting, such as formation, development, dwindling and destruction, can be taken as the uplifting cycle. The uplifts on the giant Precambrian cratons are large in scale with less extensive structural deformation. The uplifts on the medium‐ and small‐sized cratons or neo‐cratons are formed in various shapes with strong structural deformation and complicated geological structure. Owing to changes in the geodynamic environment, uplift experiences a multi‐stage or multi‐cycle development process. Its geological structure is characterized in superposition of multi‐structural layers. Based on the basement properties, mechanical stratigraphy and development sequence, uplifts can be divided into three basic types — the succession, superposition and destruction ones. The succession type is subdivided into the maintaining type and the lasting type. The superposition type can be subdivided into the composite anticlinal type, the buried‐hill draped type, the faulted uplift type and the migration type according to the different scales and superimposed styles of uplifts in different cycles. The destruction type is subdivided into the tilting type and the negative inverted type. The development history of uplifts and their controlling effects on sedimentation and fluids are quite different from one another, although the uplifts with different structural types store important minerals. Uplifts and their slopes are the main areas for oil and gas accumulation. They usually become the composite oil and gas accumulation zones (belts) with multiple productive formations and various types of oil and gas reservoirs.

Sequestration of carbon dioxide (CO2) in depleted or partially depleted oil reservoirs is an immediate, cost-effective option to reduce CO2 emissions into the atmosphere. Carbon dioxide has been injected into oil reservoirs for the purpose of enhancing oil recovery (EOR). With EOR, the goal is to maximize the oil production by minimizing the use of CO2 while with sequestration, the goal is to maximize the storage of the CO2. During EOR, a significant amount of CO2 may be sequestered in the reservoir. If CO2 emissions are regulated, the EOR process may therefore be able to earn sequestration credits in addition to oil revenues. We develop a theoretical framework that analyzes the co-optimization of oil extraction and CO2 sequestration. The economic analysis takes into account factors such as capture, transportation and recycling costs. This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery - CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir model. A simulation study is completed using a 3-D compositional simulator " ECLIPSE 300?? and an optimization algorithm in order to optimize the net present value of oil recovery and CO2 storage. A number of simulations are studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. The simulations have showed that the projects would be unprofitable for immiscible cases when using costs typical of current CO2 capture from power plants unless there is some form of credit for storage. In contrast, in miscible cases, the projects may be profitable even without considering any CO2 credits and their profitability is further enhanced with possible carbon credits. The results show that innovative reservoir engineering techniques are required for co-optimizing CO2 storage and oil recovery. 1. Introduction CO2 concentration in the atmosphere has drastically increased over the past 250 years from 280 to 380 ppm (Bryant 1997). The major cause of increasing CO2 emissions into the air has been recognized as the dramatic increase in the fossil fuel consumption for energy production. Increasing concentrations of CO2 leads to climate change via enhancing the natural greenhouse effect. Several measures have been suggested to control the problem of increasing CO2 emissions in the air. One of such measures is to decrease carbon intensity of energy production, which means less CO2 per specified amount of produced energy (Forooghi, Hamouda and Eilertsen 2009). CO2 emissions can also be reduced by increasing the share of renewable energies in the energy consumption portfolio. The most promising, immediate option for reducing a large amount of CO2 is, however, the long-term sequestration of CO2 in geological formations. Depleted or mature oil and gas reservoirs, deep saline formations, and unminable coalbeds are usually considered as the most applicable CO2 sequestration formations (Bachu 2003). Geological CO2 storage as the effective option to mitigate atmospheric CO2 emissions has been considered since the 1990's and has been implemented at a large scale for the first time in Norway (Moritis 2002). Oil and gas reservoirs are good candidates for sequestration because industrial experiences already exist for CO2 injection. Regarding economic aspects of the sequestration process, coupled enhanced oil recovery (EOR) and sequestration processes have advantages since the increased oil recovery will offset some of the costs of CO2 sequestration process. The Weyburn CO2 sequestration and EOR project is an example of commercial coupled CO2 EOR and sequestration process, which has shown a great success in terms of both objectives of the project (Malik and Islam 2000). In this project, carbon dioxide is transported from the North Dakota coalgasification plant through pipelines and is injected into the Weyburn oil field.

In the last decade, high salinity waterflooding has been emerged as a prospective EOR method for chalk reservoirs. Most recently, Saudi Aramco reported significant increase in oil recovery by low salinity waterflooding in Saudi Arabian carbonate reservoirs. Understanding of the mechanisms leading to an increase in oil recovery in both smart waterflooding processes (low and high salinity waterflooding) is still not clear. In this paper, we investigate experimentally the recovery mechanisms for both methods. To understand high salinity waterflooding process, we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations. For low salinity waterflooding, flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater. Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion phase between high salinity brine and oil with the increase in sulfate ion concentration at high temperature and pressure. We propose that the decrease in viscosity and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration, which has been reported in most previous studies. No low salinity effect was observed for the reservoir carbonate core plug at the room temperature. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of the carbonate rocks. Migration of fines, dissolution and destruction of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 °C. At the present stage, the mechanisms behind increment in oil recovery under various conditions appear to be different.

The decline in oil recovery in oil and gas fields is a problem that must be faced now and in the future along with the increasing need for petroleum energy. Increasing oil recovery reserves requires an advanced method, namely Enhanced Oil Recovery (EOR). Surfactants are one of the enhanced oil recovery (EOR) methods to increase oil recovery. This laboratory research will use a surfactant solution, namely ABS Surfactant (Alkyl Benzene Sulfonate). There are five concentrations for each surfactant, namely 0.3; 0.5; 0.75; 0.9; and 1% with the same salinity of 7,000 ppm. In this study, ABS surfactant was used because the surfactant has the characteristic of being able to reduce interfacial tension. This research carried out a phase behavior test to determine the stability of the emulsion with a measurement time of 7 days at a temperature of 80 °C. Making an ABS surfactant solution, 70% ABS fluid is available where the surfactant raw material will be mixed with brine with a salinity of 7,000 ppm. There are several stages carried out, namely density test, phase behavior, interfacial tension, and core flooding. After making a sample of the ABS surfactant solution, the second step was to carry out a density test using a DMA-4100 densitometer to determine the density of the ABS surfactant solution at temperatures of 30 °C and 80 °C. The third is a phase behavior test where the surfactant solution will be mixed with oil and then placed in an oven at a temperature of 80 °C for 336 hours to obtain emulsion results that are close to the midpoint so that the stability of the emulsion is more optimal. The fourth is to determine the IFT value with a surfactant sample that has the highest volume of microemulsion stability. Finally, the core flooding test is to determine how much oil is recovered from the sandstone when surfactant injection is carried out. In the IFT results, the ABS surfactant solution was able to reduce the interfacial tension well between oil and formation water in the reservoir, where the interfacial tension value was 0.0055654 dyne/cm. The results of core flooding with ABS surfactant with a concentration of 0.9% salinity of 7,000 ppm obtained a recovery factor of 14.545%.

This paper presents an evaluation of infill drilling opportunities in a mature waterflood. Different infill drilling configurations for increased oil recovery are compared using a ranking scheme. The field has been on production since 1976. The field has a complex development history, with periods of primary recovery, shut-in, 5-spot, inverted 9-spot, and direct line-drive waterflood. The field is currently undergoing a linedrive waterflood. The challenge is to find new infill drilling opportunities and determine optimal well spacing to maximize oil production. Traditional infill drilling evaluations either use empirical techniques based on ad-hoc esimates of drainage areas or reservoir simulation of the field-level benefits of an infill drilling program. The former approach ignores the impact of reservoir heterogeneities while the latter approach makes it difficult to evaluate the contribution that each infill well makes to the field-level benefit. Our approach isolates the impact of each infill well and provides a fast and novel methodology to evaluate the incremental benefit while accounting for reservoir heterogeneity, well conditions, pattern configuration, injection rates, and voidage replacement ratio. This type of analysis helps optimize the number of wells to be drilled and at the same time leads to increased oil recovery through better waterflood management. Streamline analysis was used to identify dead spots and regions of unswept oil in a part of the field. A novel waterflood management workflow was used to evaluate new infill well configuration strategies to increase oil recovery and better manage the waterflood. Optimization studies were also conducted to minimize the number of wells with the right combination of injectors and producers and obtain significant incremental benefits. Work is underway in the field to implement these recommendations and early results point to the success of this approach. This paper presents a novel approach for evaluating the impact of infill drilling. The marginal utility of each infill well is calculated and then is used to optimize the number of wells and maximize oil recovery. The approach presented can be used to quantify the impact of infill drilling and increase oil rate and recovery in similar reservoirs.

A streamline type mathematical model has been developed which may be used to study oil recovery by viscous waterfloods for any desired well spacing. The model was used to study the combined effects of permeability stratification, polymer concentration and viscous water slug size for a five spot injection pattern. Five different permeability profiles ranging from a homogeneous to a highly stratified reservoir were studied. It was found that viscous water floods show greater percentage increase (over conventional water percentage increase (over conventional water floods) in oil recovery for stratified reservoirs than for homogeneous reservoirs. A highly stratified reservoir containing viscous oil showed a 96% increase in recovery for a particular viscous water flood. it was also found that the adverse effect o connate water on oil recovery becomes insignificant as the degree of permeability stratification approaches a large number. Guide-lines for the determination of an optimum slug size and viscosity were derived. Generally speaking, it is advisable to use a high viscosity, small size slug in flooding a homogeneous formation, while stratified reservoirs do better with the use of a large diluted slug. It was found that there exists an optimum slug size for a given amount of thickening chemical depending upon the oil viscosity and degree of permeability stratification. The increase in oil recovery by selecting an optimum slug size may be sizeable in some instances. Introduction The role of mobility ratio in water flooding has been well established. Thickening of the injected water or otherwise increasing its resistance to flow brings about this improvement through a decrease in its fluid mobility. Early attempts to decrease the mobility of the injected water were uneconomic, but, during the past few years, the use of a high molecular weight water-soluable polymer has shown promise as an effective polymer has shown promise as an effective material in reducing the water mobility. Results from both laboratory and field pilot tests indicate that the concentrations of polymer required in the injection water to polymer required in the injection water to effect substantial increase in flooding efficiency are usually low enough to satisfy normal profitability criteria. Much has been written postulating the mechanisms by which the mobility of water is reduced by the addition of a polymer.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 109965, "Low- Salinity Waterflooding To Improve Oil Recovery - Historical Field Evidence," by Eric P. Robertson, SPE, Idaho National Laboratory, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed. Crude-oil/water/rock interactions can lead to large variations in the displacement efficiency of waterfloods. Laboratory waterflood tests and single-well tracer tests in the field have shown that injection of low-salinity water can increase oil recovery, but testing on a multiwell-field scale has not yet been undertaken. Three Minnelusa-formation waterfloods in the Powder River basin of Wyoming were compared on the basis of salinity of the formation and injection water and of reservoir characteristics. Introduction Different wetting states of crude-oil, water, and rock ensembles can yield different oil recoveries from laboratory-waterflood tests. The wetting state, or wettability, of a rock/fluid system can be altered. In the laboratory, wettability can be altered by changing the crude-oil composition, changing the temperature while aging the rock and crude oil, or by changing the temperature during water displacement. Also, water composition can have a significant effect on wettability and on oil recovery. Therefore, cases may exist in which attention to injection-water composition could increase oil recovery, and, likely, increase the economic profitability of a waterflood. An optimal composition of dissolved solids in the injection water may exist that would yield the highest oil recovery. The composition could involve many variables with respect to ionic composition and concentration, but current knowledge of how and when water composition can be manipulated to increase oil recovery is limited. Several examples of improved recovery by injecting low-ionic-strength brine have been reported for both outcrop- and field-core samples. Fig. 1 shows the potential for increased oil recovery from low-salinity waterflooding. These corefloods were performed on two cores from the CS reservoir under identical conditions except for the composition of the injected water. The conditions necessary for improved recovery, such as the type of crude oil and rock, composition of the formation and injected waters, and initial water saturation, still are not understood fully. The crude-oil/water/rock interactions that determine displacement efficiency are highly complex. Nevertheless, laboratory observations were sufficiently encouraging to justify more studies aimed at field application. The Idaho National Laboratory (INL) through funding from the US Department of Energy searched historical waterflood records for anecdotal evidence of increased oil recovery resulting from the injection of lower-salinity water to displace oil in reservoirs with higher-salinity initial formation water. The objective was to research and compare historical field data and to compare waterflood responses from low-and high-salinity injection waters.

In this paper we present the results of a technical and an economic evaluation of waterflood infill drillings in fourteen Clearfork and eleven San Andres carbonate reservoirs in West Texas. The initial waterflood recovery efficiency and the infill drilling waterflood recovery efficiency were estimated from decline curve analyses. The economic analysis was performed to evaluate the relative profitability of the waterflood infill drilling operations. For Clearfork units, the estimated initial waterflood recovery efficiency ranged from 9.54 to 32.19% of original oil in place (N) with a medium of 17.75%N; and the infill drilling waterflood recovery efficiency ranged from 13.09 to 52.56%N with a medium of 25.53%N. The medium increase in oil recovery by infill drilling was 7.78%N. For San Andres units, the initial waterflood recovery efficiency ranged from 10.68 to 39.03%N with a medium of 19.97%N; and the infill drilling waterflood recovery efficiency ranged from 13.73 to 44.58%N with a medium of 31.82%N. The medium increase in oil recovery by infill drilling was 11.38%N. A multi-linear regression analysis was used to establish regression models correlating the initial waterflood and the infill drilling waterflood recovery efficiencies to reservoir and process parameters. For the Clearfork units, the mean and standard deviation for the best initial waterflood recovery efficiency correlation were 20.39%N and 3.19%N, respectively. The mean and standard deviation for the best infill drilling recovery efficiency correlation were 29.25%N and 2.48%N, respectively. The average increase in oil recovery by infill drilling was 8.86%N. For the San Andres units, the mean and standard deviation for the best initial waterflood recovery efficiency correlation were 22.09%N and 1.45%N, respectively. The mean and standard deviation for the best infill drilling recovery efficiency correlation were 32.23%N and 2.73%N, respectively. The average increase in oil recovery by infill drilling was 10.14%N. Two cases were studied in the economic analyses. Case I economic analysis used past and projected production schedule and economic parameters. For the Clearfork units, the rate of return ranged from 18.37% to 125.2% with a mean of 53.3%. The payout ranged from 1.22 years to 6.58 years with a mean of 3.14 years. For the San Andres units, the rate of return ranged from 20.58% to 500.0% with a mean of 157.0%. The payout ranged from 0.36 to 5.43 years with a mean of 1.77 years. Case II economic analysis used past and projected production data as though the projects were initiated in January 1988. The base crude oil price of $17.50/STB was assumed in the analyses. For the Clearfork units, the rate of return ranged from 11.41% to 98.80% with a mean of 40.4%. The payout ranged from 1.45 to 6.42 years with a mean of 3.53 years. A sensitivity analysis revealed that the average payout using $12.50/STB was 4.28 years and 3.13 years using $22.50/STB. For the San Andres units, the rate of return ranged from 20.58% to 500.00% with a mean of 157.00%. The payout ranged from 2.36 to 4.91 years with a mean of 2.3 years. A sensitivity analysis revealed that the average payout using $12.50/STB was 2.18 years and 2.00 years using $22.50/STB.

The B-P gas field locates on the middle section of Region B on the right bank of the Amu Darya, Turkmenistan. In geological structure, it belongs to central uplift belt of Sandykly of Zarzhu terrace, Amy Darya basin. The higher structure parts produce gas, the lower structure parts produce gas and water and some of the low position wells produce only water. The gas reservoir’s upper parts have high resistivity, low water saturation and a obvious gas reservoir character when the lower parts have low resistivity, high water saturation with a obvious character of water in reservoir which means the gas reservoir is controlled by geological structure mainly. Meanwhile, the whole gas reservoir can be divided into four individual gas-water system based on the gas-water interface and conversion pressure of each well which means this gas reservoir is also controlled by lithology.

Biogenic formation of hydrogen sulfide has, and will, occur in most oil and gas reservoirs - particularly those flooded with sea water. Hydrogen sulfide causes high costs and serious operational problems, including reservoir souring, sulfide corrosion, iron sulfide plugging, reduced product value, and health and environmental hazards. Historically, the sulfide problem has been treated with toxic biocides, which have proven to be costly and mostly ineffective. The petroleum industry is now implementing a nitrate-based microbial treatment technology for both the prevention and removal of sulfide from reservoirs, produced water, surface facilities, pipelines and gas storage reservoirs, as well as increasing oil recovery. This innovative reservoir treatment technology recognizes that detrimental sulfate reducing bacteria (SRB), which produce sulfide, can be replaced by a naturally occurring suite of beneficial microorganisms enhanced by the introduction of an inorganic nitrate-based formulation. This designed manipulation of the reservoir ecology has been termed Bio-competitive Exclusion (BCX) technology. The Bio-Competitive Exclusion (BCX) biological process has also demonstrated significant application in the field of tertiary oil recovery. This is possible through the use of nitrate-based formulae as alternate electron acceptors and microbial nutrient. This nitrate based formulation is environment friendly and complement the naturally occurring volatile fatty acids (VFA) in the reservoir, selectively stimulating and increasing the targeted Nitrate-Reducing Bacteria (NRB). This paper discusses novel action and advantages of BCX Technology for effective sulfide suppression when compared to previous biocide treatments. It also brings into light the two main approaches to solving the sulfide problem: proactive and reactive. Several examples of the BCX technology to treat sulfide problems are illustrated These results are reinforced by reports that both proactive and reactive nitrate treatment projects are now operational at several North Sea platforms, Such reported successes have resulted in the nitrate technology being applied to other North Sea fields including Norne, Statfjord, Valhall. The BCX technology offers a cost effective technique of sulfide removal and increased oil recovery.

Chapter 8 - Gas field pilot production test and dynamic description of gas reservoir