Dissertations / Theses on the topic 'Gas condensate reservoirs. Nitrogen'

In the last decade, shale reservoirs emerged as one of the fast growing hydrocarbon resources in the world unlocking vast reserves and reshaping the landscape of the oil and gas global market. Gas-condensate reservoirs represent an important part of these resources. The key feature of these reservoirs is the condensate banking which reduces significantly the well deliverability when the condensate forms in the reservoir below the dew point pressure. Although the condensate banking is a well-known problem in conventional reservoirs, the very low permeability of shale matrix and unavailability of proven pressure maintenance techniques make it more challenging in shale reservoirs. The nanoscale range of the pore size in the shale matrix affects the gas flow which deviates from laminar Darcy flow to Knudsen flow resulting in enhanced gas permeability. Furthermore, the phase behaviour of gas-condensate fluids is affected by the high capillary pressure in the matrix causing higher condensate saturation than in bulk conditions. A good understanding and an accurate evaluation of how the condensate builds up in the reservoir and how it affects the gas flow is very important to manage successfully the development of these high-cost hydrocarbon resources. This work investigates the gas Knudsen flow under condensate saturation effect and phase behaviour deviation under capillary pressure of gas-condensate fluids in shale matrix with pore size distribution; and evaluates their effect on well productivity. Supplementary MATLAB codes are provided elsewhere on OpenAIR: http://hdl.handle.net/10059/2145.

Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world's producible reserves. Therefore, the principal objective of the thesis is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation. Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray C'I' -scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative penneabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results. The micromodel experiments have proved extremely useful for characterizing the flow behaviour . of condensate systems. The results showed that the flow mechanisms and phases' distributions were affected largely by interfacial tension, pore structure and wettability.

This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing a gas condensate reservoir and questions were raised about how much drop in flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect. Previous attempts to answer these questions have been from the perspective of a radial model. Condensate builds up in the reservoir as the reservoir pressure drops below the dewpoint pressure. As a result, the gas moving to the wellbore becomes leaner. With respect to the study by El-Banbi and McCain, the gas production rate may stabilize, or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore. This current work has a totally different approach. The effects of reservoir depletion are minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. It also assumes an infinite conductivity hydraulic fracture and uses a linear model. During the research, gas condensate simulations were performed using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.

Thesis (M.S.)--West Virginia University, 2010.
Title from document title page. Document formatted into pages; contains ix, 52 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 49-51).

A critical issue in the development of gas condensate reservoirs is accurate prediction of well deliverability. In this investigation a procedure has been developed for accurate prediction of well production rates using semi-empirical approach. The use of state of the art fine grid numerical simulation is time consuming and computationally demanding, therefore not suitable for real time rapid production management decisions required on site. Development of accurate fit-for-purpose correlations for fluid property prediction below the saturation pressure was a major consideration to properly allow for retrograde condensation, complications of multiphase flow and mobility issues. Previous works are limited to use of experimentally measured pressure, volume, temperature (PVT) property data, together with static relative permeability correlations for simulation of well deliverability. To overcome the above limitations appropriate fluid property correlations required for prediction of well deliverability and dynamic three phase relative permeability correlation have been developed to enable forecasting of these properties at all the desired reservoir conditions The developed correlations include; condensate hybrid compressibility factor, viscosity, density, compositional pseudo-pressure, and dynamic three phase relative permeability. The study made use of published data bases of experimentally measured gas condensate PVT properties and three phase relative permeability data. The developed correlations have been implemented in both vertical and horizontal well models and parametric studies have been performed to determine the critical parameters that control productivity in gas condensate reservoirs, using specific case studies. The improved correlations showed superior performance over existing correlations on validation. The investigation has built on relevant literature to present an approach that modifies the black oil model for accurate well deliverability prediction for condensate reservoirs at conditions normally ignored by the conventional approach. The original contribution to knowledge and practice includes (i) the improved property correlations equations, (4.44, 4.47, 4.66, 4.69, 4.75, 5.21) and (ii) extension of gas rate equations, for condensate rate prediction in both vertical and horizontal wells. Standard industry software, the Eclipse compositional model, E-300 has been used to validate the procedure. The results show higher well performance compared with the industry standard. The new procedure is able to model well deliverability with limited PVT and rock property data which is not possible with most available methods. It also makes possible evaluation of various enhanced hydrocarbon recovery techniques and optimisation of gas condensate recovery.

The proposed work provides a concept for predicting well performance behavior in a gas condensate reservoir using an empirical model for gas mobility. The proposed model predicts the behavior of the gas permeability (or mobility) function in the reservoir as condensate evolves and the gas permeability is reduced in the near-well region due to the "condensate bank". The proposed model is based on observations of simulated reservoir performance and predicts the behavior of the gas permeability over time and radial distance. This model is given by: The proposed concept has potential applications in the development of a pressure-time-radius solution for gas condensate reservoirs experiencing this type of mobility behavior. We recognize that the proposed concept (i.e., a radially-varying gas permeability) is oversimplified, in particular, it ignores the diffusive effects of the condensate (i.e., the viscosity-compressibility behavior). However, we have effectively validated the proposed model using literature results derived from numerical simulation. This new solution is presented graphically in the form of "type curves." We propose that the "time" form of this solution be used for applications in well test analysis. Previous developments used for the analysis of well test data from gas condensate reservoirs consider the radial composite reservoir model, which utilizes a "step change" in permeability at some radial distance away from the wellbore. Using our proposed solution we can visualize the effect of the varying gas permeability in time and radius (a suite of (dimensionless) radius and time format plots are provided). In short, we can visualize the evolution of the condensate zone as it evolves in time and radial distance. A limitation is the simplified form of the kg profile as a function of radius and time - as well as the dependence/appropriateness of the α-parameter. While we suspect that the α-parameter represents the influence of both fluid and rock properties, we do not examine how such properties can be used to calculate the α-parameter.

Thesis (M.S.)--West Virginia University, 2009.
Title from document title page. Document formatted into pages; contains vii, 40 p. : col. ill. Includes abstract. Includes bibliographical references (p. 39-40).

This study investigates near-wellbore effects during well testing in low permeability, single- and multi-layered, medium-rich to rich, gas condensate reservoirs. Theoretical results obtained from compositional simulations are validated with actual well test data. We first study well test behaviours for a range of gas condensate fluids with increasing condensate to gas ratios (CGR), from lean to medium-rich to rich. We verify that, during a drawdown below the dew point pressure, a condensate bank forms around the wellbore for all fluids studied. We show that, in the case of a medium-rich gas, as pressure increases above the dew point pressure in a subsequent build up, part of the condensate bank closer to the well dissolves into the gas, with the fluid returning to being a single-phase gas. This is different from what happens with rich gas, where the bank disappears completely; and with lean gas, where condensate saturation at the end of a drawdown and in the subsequent build up are very similar. Lean and medium-rich gas condensate fluids yield three-region radial composite derivative behaviours corresponding to dry gas away from the well, condensate bank, and capillary number effects in the immediate vicinity of the well. Only two-region radial composite behaviours are created in the case of rich gas fluids, as rates required to see capillary number effects are not reached in practice. We then study layered systems and show that composite behaviour due to condensate bank and a multi-layer behaviour are superimposed, with the condensate bank appearing on top of multi-layer effects. In addition, the production rate ratio of the most permeable layer rate to the total rate tends to one as the least permeable layer is choked by its condensate bank. We also investigated gravity effects and conclude that gravity has little impact on pressure response once the condensate bank develops near the wellbore and in particular does not create a partial penetration behaviour. Lastly, we show that drilling horizontal wells and hydraulically-fracturing vertical wells improve well productivity when pressure is below the dew point pressure. Condensate drop-out effects are minimized when wells are fractured prior to being produced.

Studies were conducted to evaluate the impact of landfill leachate discharge on the operation of waste water treatment plants (WWTPs). Two aspects of interferences were found: one is UV quenching substances, which are bio-refractory and able to penetrate the biological treatment processes, consequently interfere the UV disinfection in WWTPs. The other one is organic nitrogen, which can pass the nitrification-denitrification process and contribute to the effluent total nitrogen (TN). Also, treatability study was conducted for landfill gas (LFG) condensate. In a laboratory study, leachate samples were fractionated into humic acids (HA), fulvic acids (FA) and Hydrophilic (Hpi) fractions, the specific UV254 absorbance (SUVA254) of the three fractions follows: HA > FA > Hpi. However, the overall UV254 absorbance of the Hpi fraction was important because there was more hydrophilic organic matter than humic or fulvic acids. It was found that the size distribution of the three fractions follows: HA > FA > Hpi. This indicates that membrane separation following biological treatment is a promising technology for the removal of humic substances from landfill leachates. Leachate samples treated in this manner could usually meet the UV transmittance requirement of the POTWs. Also, nitrogen species in landfill leachates under various stabilization states were investigated. Although the effect of landfill stabilization state on the characteristics of organic matter and ammonia is well documented, there are few investigations into the landfill leachate organic nitrogen under different stabilization stages. Ammonia was found to leach out slower than organic matter and can maintain a constant level within the first a couple of years (< 10 years). The concentration and biodegradability of organic nitrogen were found to decrease with landfill age. A size distribution study showed that most of organic nitrogen in landfill leachates is < 1 kDa. The protein concentration was analyzed and showed a strong correlation with the organic nitrogen. Different slopes of regression curves of untreated and treated leachates indicate that protein is more biodegradable than the other organic nitrogen species in landfill leachates. XAD-8 resin was employed to isolate the hydrophilic fraction of leachate samples, hydrophilic organic nitrogen was found to be more biodegradable/bioavailable than the hydrophobic fractions. Furthermore, biological and physical-chemical treatment methods were applied to a landfill biogas (LFG) condensate to explore the feasible treatment alternatives for organic contaminant and arsenic removal efficiency. Sequencing batch reactor (SBR) showed effectiveness for the degradation of organic matter, even in an environment containing high levels of arsenic. This indicated a relatively low toxicity of organic arsenic as compared to inorganic arsenic. However, for arsenic removal, oxidation-coagulation, including biological oxidation, conventional oxidation and advanced oxidation followed by ferric salt coagulation, and carbon adsorption were not effective for what is believed to be tri-methyl arsenic. Among these, advanced oxidation-coagulation showed the best treatment efficiency (15.1% removal). Only reverse osmosis (RO) could reduce the arsenic concentration to an acceptable level to meet discharge limits. These results implied high stability and low toxicity of organic arsenic.
Ph. D.

It has been known that volatile oil and gas condensate reservoirs cannot be modeled accurately with conventional black-oil models. One variation to the black-oil approach is the modified black-oil (MBO) model that allows the use of a simple, and less expensive computational algorithm than a fully compositional model that can result in significant timesaving in full field studies. The MBO model was tested against the fully compositional model and performances of both models were compared using various production and injection scenarios for a rich gas condensate reservoir. The software used to perform the compositional and MBO runs were Eclipse 300 and Eclipse 100 versions 2002A. The effects of black-oil PVT table generation methods, uniform composition and compositional gradient with depth, initialization methods, location of the completions, production and injection rates, kv/kh ratios on the performance of the MBO model were investigated. Vertical wells and horizontal wells with different drain hole lengths were used. Contrary to the common belief that oil-gas ratio versus depth initialization gives better representation of original fluids in place, initializations with saturation pressure versus depth gave closer original fluids in place considering the true initial fluids in place are given by the fully compositional model initialized with compositional gradient. Compared to the compositional model, results showed that initially there was a discrepancy in saturation pressures with depth in the MBO model whether it was initialized with solution gas-oil ratio (GOR) and oil-gas ratio (OGR) or dew point pressure versus depth tables. In the MBO model this discrepancy resulted in earlier condensation and lower oil production rates than compositional model at the beginning of the simulation. Unrealistic vaporization in the MBO model was encountered in both natural depletion and cycling cases. Oil saturation profiles illustrated the differences in condensate saturation distribution for the near wellbore area and the entire reservoir even though the production performance of the models was in good agreement. The MBO model representation of compositional phenomena for a gas condensate reservoir proved to be successful in the following cases: full pressure maintenance, reduced vertical communication, vertical well with upper completions, and producer set as a horizontal well.

I Brista kraftvärmeverk i Sigtuna förbränns träflis och utsorterat avfall från hushåll och industri för att utvinna och exportera el och fjärrvärme. När rökgasen kyls ner, som en del av återvinningen av energi till fjärrvärmenätet, bildas rökgaskondensat. Direkt efter produktionen har kondensatet en temperatur av cirka 30 °C och innehåller höga halter av bland annat ammoniumkväve och vissa metaller. Efter rening av kondensatvattnet inuti verket efterpoleras det i en nyanlagd våtmark. Syftet med arbetet var främst att undersöka kvävereningen i våtmarken men även om riktvärden för utsläpp uppsatta av miljödomstolen efterlevs med avseende på total- och ammoniumkväve samt As och tungmetallerna Cd, Co, Cr, Cu, Hg, Ni, Pb, Tl och Zn. Arbetet syftade även på att bestämma våtmarkens area, volym och uppehållstid, undersöka eventuella skillnader i vattenföring mellan in- och utlopp samt undersöka vattentemperaturens effekt på kvävereningen. För att undersöka reningen togs veckovisa prover i våtmarkens in- och utlopp under nio veckor under hela oktober och november 2014. Proverna analyserades med jonkromatografi för bestämning av nitrat-, nitrit- och ammoniumhalt. Vidare användes data från Fortum, som driver verket, för att undersöka halter av kväve och olika metaller i våtmarken. Höjdmätningar med avvägningsinstrument användes för att bestämma våtmarkens volym och GPS för att bestämma våtmarkens längd och area. Vattentemperaturmätningar i våtmarkens utlopp genomfördes med hjälp av en logger under en tvåmånadersperiod. Vattenföring ut ur våtmarken räknades ut med hjälp av nivådata från en pumpbrunn vid utloppet. Resultaten visade att halterna av alla de studerade ämnena i både egna prover och från Fortum klarade riktvärdena för utsläpp till recipient. Halterna var även låga i rökgaskondensatet som lämnade Bristaverket vilket tyder på att reningen inuti verket fungerar bra. Våtmarkens area uppmättes till 2300 m2 och volymen till 940 m3. Den beräknade vattenföringen ut var i genomsnitt cirka 100 m3/dygn högre än inflödet. Fel i beräkningsmodellen kunde dock inte uteslutas som orsak till skillnaden. Vid låga lufttemperaturer verkade våtmarken klara av att kyla betydligt högre temperaturer hos rökgaskondensat än vad som vanligtvis skickas ut från verket. Därför rekommenderas att Fortum undersöker möjligheterna för minskad kylning av rökgaskondensatet för att möjliggöra en ökad reningsgrad av temperaturberoende processer i våtmarken, så som kväveavskiljning.
At the Brista combined heat and power plant in Sigtuna, wood chips and municipal and industrial waste are incinerated to generate and export electricity and distric heating. When the flue gas is cooled as a part of recycling its energy for distric heating, condensate is formed. Directly after production, the flue gas condensate has a temperature of approximately 30°C and contains relatively high levels of ammonia and certain heavy metals. After treatment inside the plant, the condensate is post-treated in a newly constructed wetland. The main aim of the study was to investigate the nitrogen removal in the wetland but also if current guideline values for effluents established by the environmental court are fulfilled in regard to levels of total and ammonia nitrogen as well as As and heavy metals Cd, Co, Cr, Cu, Hg , Ni, Pb, Tl  and Zn. The study also aimed to measure the wetland area, volume and retention time, investigate differences in water flow between the inlet and outlet as well as study the effect of water temperature on nitrogen removal. Water samples were taken weekly for nine weeks in October and November 2014 in the inlet and outlet of the wetland. The samples were analysed for nitrate, nitrite and ammonium ions using ion chromatography. Data from Fortum, the company that runs the heat and power plant, were also used to study levels of nitrogen and metals in the wetland. An optical leveling instrument was used to calculate the wetland volume and GPS was used to calculate its length and area. Measurements of water temperature in the outlet of the wetland were conducted using a logger during a two-month period. Water flow out of the wetland was calculated using water level data from a pump well connected to the outlet. The results showed that the levels of the studied compounds in samples collected in this study and by Fortum were all below guideline values. The levels were also low in the flue gas condensate leaving the combined heat and power plant, indicating that the treatment inside the plant is working well. The area of the wetland was measured to 2300 m2 and the volume 940 m3. The calculated water flow out of the wetland was at an average approximately 100 m3/day higher than the inflow, but an error in the calculation model is a possible cause of the difference. At low air temperatures, the wetland showed a capacity of cooling significantly higher temperatures of the flue gas condensate than what is usually released from the plant. Because of this, Fortum is recommended to investigate the possibility of reducing the cooling of the flue gas condensate and thus enabling a higher efficiency of temperature dependent treatment processes in the wetland such as nitrogen removal.

In gas-condensate reservoirs, gas productivity declines due to the increasing accumulation of liquids in the near wellbore region as the bottom-hole pressure declines below the dew point pressure. This phenomenon occurs even in reservoirs containing lean gas-condensate fluid. Various methods were addressed to remediate the productivity decline, for example, fracturing, gas injection, solvent injection and chemical treatment. Among them, gas injection techniques have been used as options to prevent retrograde condensation by vaporizing condensate and/or by enhancing condensate recovery in gas-condensate reservoirs. It is of utmost importance that the behavior of liquid accumulation near the wellbore should be described properly as that provides a better understanding of the productivity decline due to the originated from impaired relative mobility of gas. In this research, several gas injection techniques were assessed by using compositional simulators. The feasibility of different methods such as periodic hot gas injection and gas reinjection using horizontal wells were assessed using different reservoir fluid and injection conditions. It is shown that both the temperature and composition of the injection fluids play a key role in the remediation of productivity and condensate recovery. The combined effect of these parameters were investigated and the resulting impact on gas and condensate production was calculated by numerical simulations in this study. Design parameters pertaining to field development and operations including well configuration and injection/production scheme were also investigated in this study along with the above parameters. Based on the results, guidelines on design issues relating gas injection parameters were suggested. The various simulation cases with different parameters helped with gaining insight into the strategy of gas injection techniques to remediate the gas productivity and condensate recovery.
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In gas-condensate reservoirs, production rate starts to decrease when retrograde condensation occurs. As the bottomhole pressure drops below the dewpoint, gascondensate and water buildup impede flow of gas to the surface. To stop the impairment of the well, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state" to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region. This thesis presents an extensive experimental study on Berea sandstone rocks treated with a fluorinated polymer. Various concentrations of the polymer are investigated to obtain the optimum alteration in wettability to intermediate gas-wet. This wetting condition is achieved with an 8% polymer solution treatment, which yields maximum gas mobility, ultimately increasing the relative permeability curves and allowing enhanced recovery from gas-condensate wells. The treatments are performed mainly at room conditions, and also under high pressure and high temperature, simulating the natural environment of a reservoir. Several experimental techniques are implemented to examine the effect of treatments on wettability. These include flow displacement tests and oil imbibitions. The experimental work took place in the Wettability Research Lab in Texas A&M University at Qatar in Doha, Qatar. The studies in this area are important to improve the productivity of gas-condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future research and field applications.

Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable solution to the condensate blocking problem in gas wells. Alteration of rock wettability to neutral-wet is the primary reason for improvement in gas and condensate relative permeabilities. Stability/compatibility test, drop tests and X-ray photoelectron spectroscopy (XPS) analysis along with core flood results were used to characterize wettability changes. XPS tests, drop tests, and relative permeability measurements were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs. The method discussed in this thesis can be used to identify chemical treatments to change rock wettability and, therefore, relative permeability. This provides a simple, quick and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers which saves time, cost and effort.
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Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. This problem starts as the flowing bottom hole pressure drops below the dew point in wells producing from gas condensate reservoirs. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. The main focus in this research was to develop an effective chemical treatment to mitigate liquid blocking in gas wells producing from carbonate reservoirs. In the initial stages, screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements, drop imbibition tests, and contact angle measurements with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tools. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. Through phase behavior studies the compatibility of the treatment solution and in-situ brines were investigated to reduce the risk of failure in the coreflood experiments. The measured relative permeability values in Texas Cream Limestone and Silurian Dolomite cores are demonstrate from high-pressure, high-temperature coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with synthetic gas-condensate mixtures. To enhance the durability of the treatment a special amine primer is introduced.
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During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Several methods such as gas recycling, hydraulic fracturing and solvent injection have been tried to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods of well stimulation offer only temporary productivity restoration and cannot always be used for a variety of reasons. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid (condensate + water) blocking in gas condensate reservoirs. The chemical treatment alters the wettability of water-wet sandstone rocks to neutral wet, and thus reduces the residual liquid saturations and increases gas relative permeability. The treatment also increases the mobility and recovery of condensate from the reservoir. A nonionic polymeric fluoro-surfactant in a glycol-alcohol solvent mixture improved the gas and condensate relative permeabilities by a factor of about 2 on various outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments on outcrop and reservoir cores using synthetic gas mixtures at reservoir conditions. The durability of the chemical treatment has been tested by flowing a large volume of gas-condensate fluids for a long period of time. Solvents used to dissolve and deliver the surfactant play an important part in the treatment, especially in the presence of high water saturation or high salinity brine. A screening test based on phase behavior studies of treatment solutions and brines has been used to select appropriate mixtures of solvents based on reservoir conditions. The adsorption of the surfactant on the rock surface has been measured by measuring the concentration of the surfactant in the effluent. Wettability of treated and untreated reservoir rocks has been analyzed by measuring the USBM and Amott-Harvey wettability indices to evaluate the effect of chemical treatment on wettability. For the first time, chemical treatments have also been shown to remove the damage caused by water blocking in gas wells and for increasing the fracture conductivity and thus productivity of fractured gas-condensate wells. Core flood experiments done on propped fractures show significant improvement in gas and condensate relative permeability due to surface modification of proppants by chemical reatment. Relative permeability measurements have been done on sandstone and limestone cores over a wide range of conditions including high velocities typical of high rate gas wells and corresponding to both high capillary numbers and non-Darcy flow. A new approach has been presented to express relative permeability as a function three non-dimensionless terms; capillary number, modified Reynolds Number and PVT ratio. Numerical simulations using a compositional simulator have been done to better understand and design well treatments as a function of treatment volume and other parameters. Injection of treatment solution and chase gas and the flow back of solvents were simulated. These simulations show that chemical treatments have the potential to greatly increase production with relatively small treatment volumes since only the near-well region blocked by condensate and/or water needs to be treated.

Hydrocarbon use has been increasing and will continue to increase for the foreseeable future in even the most pessimistic energy scenarios. Over the past few decades, natural gas has become the major player and revenue source for many countries and multinationals. Its presence and power share will continue to grow in the world energy mix. Much of the current gas reserves are found in gas condensate reservoirs. When these reservoirs are allowed to deplete, the pressure drops below the dew point pressure and a liquid condensate will begin to form in the wellbore or near wellbore formation, possibly affecting production. A field optimization includes determining the number of wells, type (vertical, horizontal, multilateral, etc.), trajectory and location of wells. Optimum well placement has been studied extensively for oil reservoirs. However, well placement in gas condensate reservoirs has received little attention when compared to oil. In most cases involving a homogeneous gas reservoir, the optimum well location could be determined as the center of the reservoir, but when considering the complexity of a heterogeneous reservoir with initial compositional variation, the well placement dilemma does not produce such a simple result. In this research, a horizontal well placement problem is optimized by using a modified Genetic Algorithm. The algorithm presented has been modified specifically for gas condensate reservoirs. Unlike oil reservoirs, the cumulative production in gas reservoirs does not vary significantly (although the variation is not economically negligible) and there are possibly more local optimums. Therefore the possibility of finding better production scenarios in subsequent optimization steps is not much higher than the worse case scenarios, which delays finding the best production plan. The second modification is developed in order to find optimum well location in a reservoir with geological uncertainties. In this modification, for the first time, the probability of success of optimum production is defined by the user. These modifications magnify the small variations and produce a faster convergence while also giving the user the option to input the probability of success when compared to a Standard Genetic Algorithm.

博士
國立成功大學
資源工程學系
104
The purpose of this study is to develop general analytical equations and type curves for estimating the CO2 storage capacity of natural gas reservoirs. Numerical simulations for different types of natural gas reservoirs were done to study the CO2 storage capacity and to validate the developed analytical solutions. A simulation case study is implemented to calculate the CO2 storage capacity in a target storage site, and the simulated result of CO2 storage capacity is compared by that from the derived p/zmixCO2 plot. This study successfully derives general analytical equations and type curves. This general solution is capable of analytically calculating CO2 storage capacity of dry-gas, wet-gas, and gas-condensate reservoirs. Furthermore, this method is useful for site screening of CO2 storage in depleted natural gas reservoirs. In the gas-production stage, the z-factor of natural gas (z) decreased with the decreasing formation pressure. However, in the CO2-injection stage, the z-factor of mixed gases (zmixCO2) increased when the formation pressure was recovering. Generally, the value of the zmixCO2 was smaller than that of the z-factor of natural gas under a specific formation pressure. If the initial formation pressure (pi) is considered, the value of the pi/zmixCO2 when CO2 injection finished will be higher than that of the pi/zi of the gas-condensate reservoir. More CO2 can be stored in a gas-condensate reservoir than the amount of natural gas produced. Numerical simulations for different types of gas reservoirs were used to study their CO2 storage capacity. Additionally, the comparisons of CO2 storage capacity estimates showed that the outcomes of analytical solutions and numerical simulation were similar. The accuracy of the derived general equation was validated. For the case study, the target site was the Y gas-condensate reservoir located in the Y gas field in northwestern Taiwan. The original gas in place (OGIP) of the Y gas-condensate reservoir was about 45,540 million standard cubic feet (MMSCF) which was estimated from the p/z plot based on the measured productions, formation pressures, and corresponding z-factors. The Y gas-condensate reservoir is a nearly depleted reservoir with a very weak water drive. Geological and numerical models of the Y gas-condensate reservoir were constructed in this study. Before the simulated CO2 injection started, the numerical model was well tuned using history matching. The simulations of CO2 injection showed that the total CO2 injected was 48,870 MMSCF (2.58 million tons) when the formation pressure was recovered to the initial pressure of 4,850 psi. The injection/production ratio (IPR) calculated by the derived equation was 1.44 based on the estimates of the ratio of initial p/z and injected p/zmixCO2 (PZR), dimensionless total equivalent gas ratio (DTE), and dimensionless produced equivalent gas ratio (PEG) of 1.275, 1.088, and 1.028, respectively. The value of IPR from analytical method was identical to that derived using the numerical method.