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Abstract Geological carbon sequestration through injecting large-scale carbon dioxide (CO2) into the deep saline aquifers represents a long-term storage of CO2. In the CO2 sequestration process, the injected CO2 is displacing water from the injection point and is expected to remain in the reservoir. Due to the nature of one phase displacing another phase in porous media, it is noted that different water saturation exists in the CO2 plume during the displacement. Water distribution in the plume will affect the size of the plume subsurface. Furthermore, the gravitational segregation between CO2 and water will cause overriding-tonguing during the injection and impact the shape of plume. To better understand the CO2 movement underground and development of CO2 plume, it is necessary to take the two-phase flow and gravity force effects into account when evaluating CO2 displacing water. The displacement of water by injecting CO2 is not a piston-like process in aquifer. Because water is the wetting phase and CO2 is the non-wetting phase when two phases flow in reservoir, water occupies the surface of matrix and small pores while CO2 resides in large pores and centers of pores. As a result, various water saturations distribute behind CO2 front during the displacement. The distribution is a function of fluid and rock properties, fluid-rock interaction, and injection operation. In this study, these factors are considered when developing new models to predict CO2 plume evolution during injection. Mass conservation, multiphase flow, and equation-of-states are applied in the derivation of the models, which guarantees a rigorous approach in the investigation. The modeling results indicate that CO2 does not displace water completely away from the plume. The shape of the CO2 front is controlled by the relative permeability of two phases and capillary pressure. Water saturation profile from CO2 injecting point to the displacement front shows that water saturation behind the CO2 front increases outwardly, and the change in saturation is non-linear. The injection rate impacts the sharpness of the CO2 front, thus leads to different gas plume sizes for same injection volume. The outward movement of the CO2 front decelerates as injection time goes on. The research illustrates that injection experiences two stages: transient and steady-state, in which the displacement behavior and the development of gas plume vary. Although the duration of transient stage is dictated by size of aquifer and is relatively short comparing with steady-state stage, its influence on the development of CO2 plume cannot be neglected when selecting gas compressor horsepower and determining injection rate.

Abstract The low recovery of oil from the tight liquid-rich formations is still a main challenge for the tight reservoir. Thus, in order to break the chains and remove the obstacle such as the low recovery factor in the Bakken tight formation, even though the horizontal drilling and hydraulic fracturing technologies were already well applied in this field, the supercritical CO2 flooding was proposed as an immense potential recovery method for the production improvement. In this research, we conducted a series of CO2 flooding experiments under various injection pressure (2500psi, 2800psi, 3000psi, 3500psi), to investigate the recovery potential of the core sample from Bakken tight formation. Also, the NMR analysis was processed of the core samples flooded with CO2 agent under the above injection pressure variables. The result comparison demonstrates that, with the supercritical CO2 injection pressure increase, the recovery factor gets incremental trend from 8.8% up to 33% recovery. Also, the macro pore and natural fracture system were proved to contribute more on the recovery potential. After reaching the miscible phase between the CO2 and oil in the sample, the hydrocarbon existed in the micro pores start the contribution to the recovery potential. Thus, The CO2 was identified as a potential recovery agent and the supercritical CO2 EOR method was proposed as the potential recovery technology due to the high recovery factor obtained in the immiscible and miscible processes.

Abstract Geological carbon sequestration represents a long-term storage of CO2, in which large-scale CO2 is injected into the subsurface geologic formations, such as the deep saline aquifers or depleted oil and gas reservoir. In the CO2 sequestration process, the injected CO2 is expected to remain in the reservoir and not to migrate to the earth surface. To better understand the CO2 movement undersurface and obtain real time information in carbon sequestration, an iridium oxide-based Severinghaus-type CO2 chemical sensor was constructed and tested in this study. The CO2 sensor was designed and constructed based on the intersection inspiration from electrochemistry idea. The principle of the CO2 sensor design is dramatically rely on the pH detection of the electrolyte solution which generated by the hydrolysis process of CO2. The developed CO2 sensor includes a couple of Iridium-Oxide electrodes. To meet the working purpose, iridium oxide nanoparticles was prepared and electrodeposited for the thin IrO2 film generation on the surface of metal substrate. The other critical parts, such as a thin gas-permeable silicone membrane, a porous metal supporting material, and the bicarbonate-based electrolyte solution are prepared for the sensor's preparation. The assembled sensor was tested in aqueous solution with different CO2 concentrations. Then the sensor was settled in harsh, high-pressure environments, in order to invest the performance of the CO2 sensor under reservoir conditions. Introduction The definition of CO2 sequestration was the whole process of the CO2 capture and the CO2 long-term storage [1]. It had been treated as a potential method to decelerate the accumulation process of greenhouse gas which generated from the fossil fuels burning and other source [2]. While for the geologic sequestration, it means to put the captured CO2 in the geological formation for the aim of long-term storage.

Effective fracture properties that contribute to the flow in the tight formations are very important in stimulation job evaluation, productivity estimation, and production forecast. However, there are no direct measurements on the volume of stimulated region or the effective permeability of fracture because hydraulic fractures not only stimulate local matrix, but also connect natural fractures. Therefore, the effective drainage volume contributing to production can be much bigger than the extension of hydraulic fractures. After a high initial rate, production data for stimulated tight formation has an extended transient flow period in which the matrix functions as a source and behaves in a transient fashion. This behavior can be captured by a dual-porosity model with transient matrix performance under a constant bottom-hole pressure. This paper studies the problem from an inverse perspective and couples the production data with an interporosity flow model to estimate the effective drainage volume that a well controls as well as the effective permeability that can be used for production rate forecast. The problem is solved in Laplace domain. The proposed model is validated with the numerical simulation and the field production data from Mississippian Lime. Furthermore, the interporosity model is sufficient to forecast the production trend from the given examples.

Multi-fractured (multi-frac) horizontal wells have emerged as an advanced mean for enhancing well productivity in low permeability reservoirs, being used to advance the development of shale oil and shale gas reservoirs. Fluid transport in the fracture domain is dominated by the fracture effect. In the non-fracture domain mainly representing the area of fluid flow from reservoir boundary to the fracture domain, there exists a threshold pressure gradient. The fluid in low permeability porous media is not able to flow until the reservoir pressure gradient is greater than a minimum value. Due to the complexity of reservoir simulations for multi-frac horizontal wells in low permeability shale reservoirs, a reliable mechanistic model is needed for production engineers. The analytical solution to well performance in multi-frac horizontal wells has been studied by different researchers. None of the models considered the effect of multiple phase fluid flow. These models were further weakened by using the constant fluid properties. This paper presents a rigorous model used to predict multi-frac horizontal well performance for low permeability reservoirs, under the effects of reservoir threshold pressure gradient and non-constant fluid properties while also considering the impact of multiphase flow through non-fracture and fracture domains. The effect of pressure dependent reservoir properties was often overlooked in multi-frac horizontal well models. In general, the significant pressure difference across the reservoir boundary and at the wellbore results in the changes of fluid viscosity, and density. The existing single phase and constant fluid property models overestimate production rates, while that predicted by the new, multi-phase model better matches the field production rate.

Temperature measured from a permanent downhole gauge in a well after the well shut-in provides a unique perspective for surveillance and production management purposes. For example, in deepwater environment, production engineers need to know the temperature status of a shut-in well before it is being restarted since different temperature profiles along the wellbore may need very different restarting strategies for flowing assurance purposes. A number of "rule-of-thumb" or complicated numerical simulations are either not reliable or impractical. This paper presents a semi-analytical model to estimate the temperature transient behavior after the well shut-in. The model is solved numerically through inverse Laplace transform and integration. This solution gives temperature distribution profile and history in any location along the radial direction for a given production time and shut-in duration. To make it more general for other wells, an empirical correlation is provided through regression on the calculated type curves. The difference between this semi-analytical solution with other previous efforts will be discussed. The applications of the solution to this model are multiple folders. For example, we can use the solution to predict the temperature behavior after the well shut-in, which can be used for flow assurance purposes. Furthermore, matching the calculated temperature with the measured temperature at the same location will yield the well local heat transmissibility coefficient. Some field examples are provided to demonstrate these applications.

Abstract The free gas evolved in the pump chamber results in a low rod pump working efficiency, and it can even lead to a failure. A common and effective solution is to install a downhole gas separator before fluid entering the chamber, which can divert the free gas to the annulus. If we can re-inject the diverted gas back to the tubing at a shallower depth above the pump, the flowing gas is then re-combined with the liquid and decreases fluid density. Consequently, the injected gas also creates additional lifting drive for the liquid. A new technology based on this concept has been developed and called Casing Gas Assisted Rod Pumping (CGARP). This paper firstly presents an analytical model to optimize the overall lifting performance and minimize the operating expenditure. It is especially useful in producing hydrocarbon at high GOR. As the gas is re-combined with the liquid above the pump installation depth, the hydrostatic pressure gradient is reduced consequently. However, if the gas reinjection valve is placed at a shallow depth, the well segment at reduced fluid density is subsequently short, so the contribution of gas lift is restricted. Vice versa, if the gas reinjection valve is placed at the depth close to the pump, it requires high pressure to open the gas injection valve, so the gas reinjection can happen infrequently and the production rate is unstable. This paper has proposed a genetic optimization method to maximize the overall production system efficiency. A multi-variable vector has been defined, which includes pumping speed and depth, mechanical power, rod string diameter and length, surface stroke length, downhole separator efficiency, as well as gas reinjection valve depth. The optimized object can be the system lifting efficiency or Net Present Value, which must be a function of this vector in the constraint of mass and momentum conservations. This work has been applied as the primary guide for four oil producers with rod pump installed in Jilin field, China. The average system lifting efficiency and production rate have been increased by 20% and 15% respectively. This analytical model has enhanced the field performance. Most importantly, the same concept can be applied for other pump-assisted wells. Introduction For oil fields with high GOR, gas lift method can be an ideal candidate (Redden, et al., 1974; Herald, 1987). However, because of the high capital expenditure, limitation of available gas, and complexity of the surface system, the rod pumping system has been generally adopted in field. On the other hand, for the high GOR fluid, the release of solution gas inside the rod pump can notably deteriorate its working performance. As an effective and common solution, the Downhole Gas Separator (DGS) or anti-gas pump can restrict the free gas entering the pump and thus improve the pump efficiency (McCoy and Podio, 1989; Dottore, 1994). Unfortunately, the separated gas is usually discharged through the casing, and later mixed with the liquid flow lines at surface. As a result, the energy of this casing gas is not utilized above the pump setting point. A new concept of Casing Gas Assisted Rod Pumping (CGARP) system has been introduced earlier (Liu et. al 2007). The free gas separated after DGS can be re-injected from the annulus into the tubing above the pump installation depth. After re-combining the gas with the liquid, the fluid density is reduced. Thus, the producer can have an enhanced production rate in the favor of both pump- and gas-lift assistances, as shown in Fig.1.

To maximize the production rate and develop marginal/unconventional fields, all kinds of intelligent wells have been proposed and practiced in field, including multi-stage fractured horizontal well, multi-lateral or fishbone completions. Undulating horizontal well, also called snaky well, is one of the most common intelligent completions nowadays. This paper presents a semi-analytical model for undulating horizontal well, which predicts not only the inflow from reservoir and pressure drop inside the wellbore, but also takes into account the interference among well segments. As the undulation index and cycles increase, the undulating completion can result in a good effective vertical permeability and inflow. Although the advantage is marked, the related technical challenges and high cost are increased correspondently. Thus, an optimization of the undulation index and cycle is required to maximize the project Net-Present-Value (NPV). Along with appropriate economic analysis, the proposed semi-analytical model can suggest and evaluate the field development in a time manner. Further, the undulating well can be a substitute for multi-stage fractured horizontal well, especially for dual porosity shale gas/oil fields.

This paper presents innovative iteration algorithms for multi-interface heat transfer in pipe flow. To the best of our knowledge, this is the first approach derived from Drift-flux Model (DFM), which is more competent than mechanistic models for high slippage gas-liquid flow. Consequently, the temperature/pressure distribution profiles can be accurately captured under transient condition. For waxy crude fields, it's critical to sustain the flowing temperature above the Wax Appearance Temperature (WAT). This is especially challenging for gas-lift assisted wells. The injected gas, commonly at relatively low temperature, leads this flow assurance problem sophisticated. An effective practice is to heat up the flowing fluid by installing an electrical cable in tubing. Such the heat exchange happens at three interfaces in the production system: between cable and flowing crude, flowing crude and injected gas, injected gas and formation. Therefore, it is challenging to model such a multiphase production system including an inner annulus inside tubing as the electrical able installed, and an outer annulus where the gas is injected. To optimize this production system, a rigorous transient multiphase and multi-interface heat transfer simulator has been demanded. With explicitly integrating with the subsurface boundary condition, our new algorithms can optimize the cable length, heating period, supplied power, or gas injection rate for the aforementioned production system. This new method has been successfully applied for several gas-lift assisted wells in a waxy crude field located in north China. The power consumption has been noticeably decreased by 30% than the historical field performance. The delegated optimization scheme reduces the shut-in time in winters, which has promised a cost-saving development. The presented model not only satisfies the exceptional modeling requirements for periodically-heating crude producers, but also it is appropriate for other heat transfer investigations under transient multi-interface and multiphase flow condition.

This paper presents analytical algorithms to calculate ultimate recovery factors for radial flow systems. The approaching method is similar to the well-recognized Buckley-Leverett equations, but it's accurate for matured fields, especially peripheral water-flooding reservoirs. Buckley-Leverett displacement equations have been derived strictly from linear flow systems, and have been verified by linear flow experiments only. However, nowadays, it's very common to observe multiple water injectors drilled around producers to enhance the recovery factor in mature fields. New analytical equations that consider non-linear flow patterns are more appropriate for these types of operations. The new equations proposed in this paper have been verified with real field data. The original Buckley-Leverett equation generally results in much lower recovery factors that barely match the cumulative production. Consequently, the estimated ultimate recovery (EUR) by volumetric methods tends to be too low. As a result, the production projections according to match this EUR are not reasonable when compared to the historical performance of the wells and Decline Curve Analysis (DCA). The proposed analytical model improves the prediction of reservoir performance. It works as an important supplement to the Buckley-Leverett method for oil fields worldwide.

Abstract Permanent Downhole Gauge (DHG) technology has been widely used in deep water reservoir development in the last decade and is playing an increasingly significant role in real time reservoir/well surveillance and reservoir management. Tidal signal extracted from the highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock pore compressibility. Most previous works treated tidal signal as pressure "noise" and little has been discussed on how to utilize the tidal information in reservoir characterization. This paper will address how to use Fast Fourier Transform (FFT) to extract the tidal signal and the theory and method to process the signal for reservoir characterization purposes. In addition, several examples from some deep water fields will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid saturation change, and detect the presence of secondary gas cap. This paper will show that FFT is a fast and reliable method to process the DHG pressure data for tidal signal which can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signal are very unique because they cannot obtained in laboratory, simulation, or direct measurements because of the scale impacted by tides.

Abstract Nitrogen injection into gas condensate or volatile oil fields has been practiced as a method of pressure maintenance as well as enhanced hydrocarbon recovery in Rocky Mountains for more than two decades. Reservoir management has experienced miscible displacement in the gas cap, reservoir pressure maintenance, and reservoir blow down in different fields. In the implementation of nitrogen injection, a tremendous amount of experiences on injection and reservoir performance had been accumulated without appropriate documentation. Furthermore, even though nitrogen injection has been widely used in the world to enhance recovery by miscible displacement or maintaining reservoir pressure, literature survey shows that the experience with nitrogen injection is sporadic. This paper reviews reservoir characteristics and summarizes the lessons learned from nitrogen injection all of the world; then focuses on Rocky Mountains reservoir management to further analyze its production and surveillance, reservoir development stages in the life of fields, and the relationship between the fields and processing facility. Compositional reservoir simulation was performed to study the enhanced hydrocarbon recovery by injecting nitrogen and use nitrogen breakthrough information across the field as a continuous tracer to study the well connectivity between the injector and producer pairs. The main contributions of the paper are that it highlights the accumulated experience associated with nitrogen injection, and provides information on amenable reservoir features which can be used to select nitrogen as a viable alternative for enhanced oil recovery purpose. Introduction Nitrogen injection to hydrocarbon fields to maintain pressure and enhance hydrocarbon recovery has been used widely in different formation and fluid types, and significant amount of experiences with reservoir surveillance, nitrogen separation and hydrocarbon processing, and fluid phase behavior have been accumulated and documented (Sinanan and Budri 2012; Sanchez et al. 2005). In Rocky Mountains, the fields are of particular interest because of the fluid type and formation characteristics. Nitrogen injection into gas condensate or volatile oil fields in Rockies has been practiced for more than three decades. A number of fields (Figure 1) such as Painter Reservoir Units (PRU), and Ryckman Creek in overthrust, Anschutz Ranch East (ARE), and Glasscock Hollow, used large amounts of nitrogen to increase hydrocarbon recovery as well as to maintain reservoir pressure. Some of the fields with reservoir characterizations had been presented in literature (Clancy and Gilchrist 1983). In these fields, gas condensate/volatile oil was initially produced driven by gas expansion, supplemented by solution-gas and some with aquifer. After initial production, dry gas-re-injection and nitrogen injection was implemented. The experience associated with nitrogen injection and characteristics of reservoir development are valuable information for future nitrogen injection projects. These fields are situated on the hanging wall of the Utah-Wyoming thrust belt, and they are producing from Upper Triassic-Lower Jurassic Nugget formation as shown in Figure 2. Some key parameters about the fields are compared in Table 1. A general stratigraphic description about the formations is presented in Figure 2. Some major fields such as PRU and ARE have been produced from the nugget formation which comprises Aeolian dune and inter-dune/sand-sheet sandstones with a stratigraphic thickness of approximately 900ft (Ring et al. 1999). The reservoir fluids are gas with volatile oil, and gas condensate, respectively. A brief introduction about reservoir characteristics is as follows.

Abstract Generally reservoirs are classified into five categories according to the reservoir fluids. Single phase flow in reservoir is expected during the production life for wet gas and dry gas reservoirs. But for black oil, volatile oil, and gas condensate reservoirs, two-phase flow will occur after pressure declines to saturated pressure and the second phase saturation reaches the critical saturation. Theoretical derivation of single-phase flow into vertical well had been done by former investigators. The solutions to different boundaries at different flow status were provided through different simplifications and assumptions. These solutions provide powerful tools for reservoir study. But when it comes to oil and gas two-phase flow, they cannot be applied. To the best of our knowledge there is no rigorous and theoretical derivation for the oil and gas two-phase flow into the well. In this study, rigorous and theoretical derivation of oil and gas two-phase flows from reservoir into the well was conducted. Starting from the famousDarcy's equation, the flows of oil and gas are controlled by the rock/fluid properties, pressure, and temperature condition. The continuity equation was applied. With the combination of equations of state and the concept of compressibility, the governing equation of oil and gas two-phase flow was constructed. Even numerical approach is required to solve the equation to get gas and oil flow rates, the new equation still has its significance due to its theoretical and rigorous derivation. It can be used as a unique tool to solve the saturated oil and gas condensate reservoirs that experience two-phase flows. The proposed equation addresses the rigorous derivation of two-phase flow in a radial reservoir. It eliminates the uncertainty in the empirical equation and has the advantage of quickness and simplicity comparing with reservoir simulation method. It becomes a powerful tool for petroleum engineers.

The decline curve analysis (DCA) is one of the most important methods in production forecast. It has been widely used among all the dynamics methods to estimate recoverable hydrocarbon. Decline curve can be divided into three categories: exponential decline, hyperbolic decline, and harmonic decline. Superficially decline curve analysis is the simplest prediction method, but as we dig into the base for DCA we find that it is not as simple as we think before. The opinion that DCA just follows the production trend can lead to tremendous errors, or even ridiculous results. A good DCA requires a solid background in reservoir engineering, production engineering, and even drilling engineering. In-depth knowledge is necessary on studied reservoir, surface production facility, and the drive mechanism. In this study, several tactics developed from experience are applied to get practical and effective DCA and some pitfalls are pointed out to avoid the error or inappropriate forecast in DCA. With these tactics and pitfalls in mind, DCA can be a very useful and powerful tool in predicting recoverable hydrocarbon. Applying the established tactics and acknowledged pitfalls presented by this paper would lead to an accurate production forecast and reasonable reserves evaluation.

Overpressure gas reservoirs with close-boundary typically have downward curving in p/z plot. The overestimations of original gas in place (OGIP) caused by incorrect extrapolations of early production data are often observed in reserve evaluation. To eliminate this error, a comprehensive compressibility term that includes the rock compressibility, water compressibility, and gas solubility in water has been introduced into the p/z plot. To satisfy the above objective, it's critical to obtain the right average reservoir pressure corresponding to the drained gas reserve at the time point. But for overpressure gas reservoirs, if we completely ignore the permeability changes as the reservoir pressure declines, the reservoir performance cannot be representative. Another substantial deficiency of the conventional method is that the solution gas in connate water is also habitually neglected in estimating the OGIP. As a result, the contribution of solution gas to the total gas production is omitted in the material balance equation (MBE). These lead to the inaccurate estimation of the OGIP and gas reserve. Considering the permeability is not constant throughout the reservoir life, but a function of pressure, rock and fluid properties, production volume, and original pore volume, a new form of MBE is presented by this study. It includes the effects of the permeability change due to pore compaction and the contribution of solution gas in connate water to the total gas production. With the proposed semi-analytical equations, the average reservoir pressure and reservoir deliverability can be estimated accurately. Therefore the evaluations of OOIP and recoverable gas are more reliable.

The rising speed of gas kick is an important parameter in well control operation. The position of the gas kick dictates the pressure at the casing shoe, which is usually the weakest point in the openhole section, and the wellhead pressure, which is one of the key factors affecting the blowout preventer and choke folder. In this research we derived a rigorous model to estimate the rising speed of gas kick. Starting from the force analysis and mass conservation we developed the equation to calculate the forces exerting on the gas kick. With the mass of the gas kick the rising speed of the gas kick is calculated. The effect of wellbore temperature profile on the rising of the gas kick is taken into account in the derivation. Before the development of this model, the estimation of gas kick position is commonly based on experience. In most cases the experience alone is not good enough in well control. The proposed model provides a new approach with solid theoretical base to characterize the rising of gas kick in the hole. With that the whole process of the well control becomes simple and drilling engineers can control the well comfortably. The method can be combined with engineers experience to predict the downhole situation, shut-in casing pressure, and mud rate as functions of position of gas kick. Any deviation from the forecast indicates accidents or downhole problems. Therefore the proposed model is a valuable tool to diagnose the problems in well control.

Along with the development of unconventional resource, an increasing number of researches and field operations have been focusing on horizontal shale gas well. The most crucial element of a horizontal well is to enlarge the drainage area, subsequently enhance the well productivity. The technique of hydraulic fracturing has been accepted as an industry standard in developing shale gas play. Therefore, the casing-cement-shale system in the horizontal well should be able to survive from any potential variation of temperature and pressure during well stimulations. The current horizontal well design for casing burst resistance and collapse resistance have been improved by some researchers. Little research can be found to consider the mechanical behavior of shale during the development of a horizontal shale gas well. This paper focuses on the instability of shale behind the casing and cement in a horizontal shale gas well. The variation of Von-Mise stress with time resulting from the wellbore flowing fluid in the horizontal well is predicted. The proposed model also quantitatively elaborates the difference of temperature distribution in horizontal shale cased hole and open hole. Well stimulation fluid with lower temperature is found to increase the risk of failure in the horizontal shale well. With the model, the down-hole instability of shale gas play in horizontal wells can be evaluated confidently.

The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap. In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.

The famous Arps empirical decline curves provide a powerful and practical tool for production forecast. Numerous historical production data proved that Arps decline curves can be applied universally. With that many engineers use Arps decline curve without knowing reservoir properties and operating conditions. The lack in reservoir properties and operating conditions affects the quality of production forecast. Even with the knowledge of reservoir properties and operating conditions a reliable production forecast still cannot be guaranteed if we do not understand the theory that connects reservoir properties and operating conditions to production decline. The demand for a solid theoretical basis for production decline curve analysis trigged this study. In this investigation, we derived the governing equations of production decline for different reservoirs by combining static geological and reservoir data with dynamic production data. With these equations the Arps decline curves are reproduced for different reservoir fluids and drive mechanisms. These equations indicate that Arps decline curves not only are empirical but also have theoretical bases. Engineers can use our governing equations to forecast production confidently.

Natural gas exploration and production from shale gas formations have gained great momentum throughout the world in the last decade. Producing natural gas from shale is challenging because of the high uncertainty in well productivity. It is imperative to investigate and understand the gas flow mechanism in the shale gas formations. This paper investigates the shale gas production mechanism based on field case studies.Guo et al.’s analytical well productivity model was employed in this work for analyzing gas productivity of a shale gas well in the Fayetteville Shale basin. Model analyses indicate that shale heterogeneity (natural fractures/custers and organics spots) is a favorable characteristics of shale gas reservoirs because they contribute to the initial and long-term well productivity. Shale gas reservoirs without natural fractures/clusters will not produce natural gas at commercial rates even a few hydraulic fractures are created. The intensity of natural fractures/clusters is a key factor affecting the potential of shale gas wells. Hydraulic fractures are useful for intersecting natural fractures/clusters to make well more productive, but it is not necessary to create high-conductivity fractures for this purpose. Shale gas wells should be placed in the areas where high-natural fracture intensity and solid organic material contents are present.

In this study, a transient multiphase simulator has been used to characterize the fluid-hammer effects of well shut-in and start-up on the coupled subsurface and surface systems. The original work was performed by applying sensitivity analysis on a typical production system that includes well completion, wellbore, downhole equipment like packer etc., and the associated surface equipment like flowline, riser and valves. The data used in the study was taken from the published literature to summarize the general course of key factors that worsen the fluid-hammer effects. Fluid-hammer is also known as water hammer, a shock wave produced by the sudden stoppage or reduction in fluid flow. Field operations such as pressure transient analysis, facility maintenance and workover require well shut-in process. For a typical production system, the resulted sudden rises in pressure can be critical because it has direct impact on equipment including unsetting of packer and may also cause possible damages to instrumentations. This paper provides estimates of the typical ratio of transient shock in pressure and flowrate over pre-condition values, and the duration of such pressure shocks. It also proposes the best location of the shut-in valve and the length of flowline to reduce the fluid-hammer effects. This is a pioneering approach to integrate multiphase flow modeling of transient fluid-hammer effects, targeting flow assurance issues. This approach also can be applied to surface facility design and served as guidance in field operation to avoid hydrocarbon leaks.

In the boom of unconventional resource exploration, horizontal completion has been widely used. Horizontal well has the advantages of increasing productivity index, preventing gas or water coning, avoiding sanding out, enhancing drainage area, reducing drilling pad and footprint, and accelerating recovery. Although these advantages have been well recognized over vertical completion, the quantitative contribution is not yet to be investigated. The current design of horizontal well is primarily derived from field experience. This consists of more or less arbitrary contents. To fill this gap, this paper presents a model to incorporate production from different lengths of horizontal well, cost of the drilling and completion, discount of revenue, and cost by different timing. The achieved optimum horizontal well design leads to a maximized net present value (NPV) for operators.

Multiphase flow in pipe has been intensively investigated since the oneset of oil and gas transportation by pipelines. As flow assurance problems keep arising in recent years, pipeline design solutions are desired for multi-phase flow system. The algorithms have widely guided the design of stream transportation from offshore well head to onshore terminal or platform. Operators would always seek cutting platform number or shut-in producing marginal field whose reserves cannot justify the construction cost. An accurate design of multiphase flow pipeline system is by all means demanded. Traditional studies focus on gas-oil two-phase flow by deriving empirical or semi-empirical correlations that fit the experimental data. This study investigates a gas–oil–water three-phase pipe flow system. Starting from the momentum and mass conservation equations, force balance, and interaction relationships between different phases, we developed analytical solutions to estimate the pressure drop for stratified flow regime. This general approach can be applied to any gas-oil-water flowing systems. It provides a solid base for nodal analysis, pressure drop calculation for multiphase flow, artificial lift evaluation, etc. to help design and optimize production system. This work can be particularly useful for steady-state distance transportation.

Gas transient flow in pipeline and gas tank is critical in flow assurance. Not only leak detection requires a delicate model to simulate the complicated yet drastically changed phenomena, but also pipeline and tank design in the metering, gathering, and transportation system demands an accurate analysis of gas transient flow, through which efficient, cost-effective operation can be achieved. Traditionally there are two types of approaches to investigate gas transient flow: one is treating gas as ideal gas so that ideal gas law can be applied; another is considering gas as real gas thus gas compressibility factor comes into play. Needless to say, the former method can result in an analytical solution to gas transient flow yet with a deviation from the real gas performance, which is very crucial in daily operation. The latter approach needs numerical method to solve the governing equation, thus leads to unstable issue but with more accurate result. Our literature review indicated that no study considered the effect of changing gas viscosity on the transient flow is available. Therefore, this effect was included in our study. Our investigation showed that viscosity does have significant influence on gas transient flow in pipe and tank leakage evaluation. In this study, a comprehensive evaluation of all variables was done to find out the most important factors in the gas transient flow. Several case studies were used to illustrate the significant of this study. Engineers can do a more reliable evaluation on gas transient flow by following the method we used in our study.

The famous Buckley-Leverett displacement mechanism has been used to predict the performance of waterflood. With Buckley-Leverett method, oil recovery from waterflood is calculated and required water injection volume to achieve that oil recovery is estimated. This method does provide a very useful tool in waterflood design. Our experience in oil industry and a thorough literature review indicates that petroleum engineers used Buckley-Leverett method to analysis waterflood project directly without any adjustment basing on the real reservoir and production situations. By doing so, a lot of errors are introduced into the analysis. It should be noted that Buckley-Leverett method assumed displacement occurs in a linear system. This is true for some waterflood scenarios while for others it is not. For some waterflood scenarios a radial system is more appropriate than a linear system. In this study we investigated the fractional flow in a radial system and derived the solutions to predict the performance of water displacing oil in radial system. With this radial displacement model, design and prediction of waterflood can be achieved by Buckley-Leverett method or our model, whichever fits the waterflood pattern. Considering the fact that many waterflood scenarios follow radial displacement, our model is an important supplement to Buckley-Leverett method.

Chokes are used to limit production rates to meet sale contract, comply with regulations, protect surface equipment from wearing out, avoid sand problems due to high drawdown, and control flow rate limited by capacity of the facility. Single gas phase flow through choke is vital to oil industry because not only an accurate estimation of gas flow rate guarantees a reliable supply to the end users, thus the predictable revenue from gas sale for the company, but also protect the equipment from breaking as a result of high gas rate. Nevertheless, importance of gas metering cannot be overemphasized. Gas flow through choke had been studied by numerous investigators, Different choke flow models are available from the literature, and they have to be chosen based on the flow regimes, that is, subsonic or sonic flow. The most common used flow equations developed by Shapiro, Zucrow and Hofmann are used for subsonic and sonic flow, respectively. Sonic flow happens when downstream to upstream pressure ratio is equal to critical pressure ratio. A careful review of these equations indicated that they are not theoretically rigorous and give inaccurate gas flow rate for the real gas. Thus these equations need to be modified in order to be used to calculate gas flow rate under both flow regimes. After a thoroughly analysis and derivation we came up with equations that have solid base. New correlations that reconcile the issue caused by approximation method used to derive the old gas flow equations were based on both engineering judgment and physical phenomenon. The error in the old equation can be corrected with the new equations. New equations provide good approaches to quantify gas flow through choke.

For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study. The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.

Rock permeability is one of most important rock properties for fluid flow in reservoir. According to Darcy’s law flow rate is proportional to permeability holding other variables constant. The methods to get permeability include direct core measurement, well test interpretation, estimating from nuclear magnetic resonance (NMR) logs, and calculating from other properties such as porosity using correlations. It is noted that these methods have their own limitations. Core measurement is expensive, time consuming and limited by core availability. NMR logs are high cost. Correlations are often obtained from scatter data point thus their reliabilities cannot be guaranteed. Therefore new method needs to be found to get permeability. Starting from multiple-capillary tubes concept, we derived a rigorous relationship between permeability and formation resistivity factor. Through this correlation permeability can be calculated from known formation resistivity factor or vice versa. Since formation resistivity factor is often obtained from lab experiment, the new correlation provided an important supplement in permeability estimation without additional cost. In other words, if permeability is known, the new correlation can be used to verify the formation resistivity factor measured from lab experiment, again, without adding cost. The new correlation also provides a unique approach to quantify the radius of capillary tube, which is not available in the literature before this study.

Oil and gas reserves are the most important assets for oil companies. An accurate estimation of reserves not only helps listed oil companies prepare solid annual reserves reports required by SEC, but also guarantees the good reward from divesting assets or reasonable price to farm-in asset. A precise reserves calculation is the fundamentality for production forecast, which is vital to the sale contract, thus the feasibility of project. It controls the cash flow and most of all the sustainable development of the company. The importance of reserve estimation cannot be overemphasized whatsoever. We know that in the practice of exploration and production, all efforts are to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure and temperature. Due to the instrument sensitivity, limitation, measurement error, environmental effect, sample interval, location, the representative of sample, and Mother Nature of these properties, there is always uncertainty. In this research, a systematic study on the effects of fluid and rock properties on reserves estimation had been conducted. Effect of each property on reserves estimation is quantified through sensitivity analysis. As a result of this study, a comprehensive picture of how fluid and rock properties affect the reserves was brought to engineers. Reserves evaluator can use this to estimate the range of reserves as a consequence of uncertainty. With this study, we realized their different impacts on reserves. Therefore main efforts should go to the variables that affect the reserves most.

Abstract Gas viscosity is an important fluid property in petroleum engineering due to its impact in oil and gas production and transportation where it contributes to the resistance to the flow of a fluid both in porous media and pipes. Although the property has been studied thoroughly at low to intermediate pressures and temperatures, there is lack of detailed knowledge of gas viscosity behavior at high pressures and high temperatures (HPHT) in the oil and gas industry. The need to understand and be able to predict gas viscosity at HPHT has become increasingly important as exploration and production has moved to ever deeper formations where HPHT conditions are more likely to be encountered. Knowledge of gas viscosity is required for fundamental petroleum engineering calculations that allow one to optimize the overall management of a HPHT gas field and to better estimate reserves. Existing gas viscosity correlations are derived using measured data at low to moderate pressures and temperatures, i.e. less than 10,000 psia and 300 oF, and then extrapolated to HPHT conditions. No measured gas viscosities at HPHT are currently available, and so the validity of this extrapolation approach is doubtful due to the lack of experimental calibration. The falling body viscometer is selected to measure gas viscosity for a pressure range of 3,000 to 24,500 psia and temperature range of 100 to 415 oF. Nitrogen was used to calibrate the instrument and to account for the fact that the concentrations of non-hydrocarbons are observed to increase dramatically in HPHT reservoirs. Then methane viscosity is measured to reflect the fact that, at HPHT conditions, the reservoir fluids will be very lean gases, typically methane with some degree of impurity. The experiments showed that while the correlation of Lee et al. accurately estimates gas viscosity at low to moderate pressure and temperature, it does not provide a good match to gas viscosity at HPHT conditions. Introduction HPHT gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300ºF. Modeling the performance of these unconventional reservoirs requires the understanding of gas behavior at elevated pressure and temperature. An important fluid property is gas viscosity, as it is used to model the gas mobility in the reservoir that can have a significant impact on reserves estimation during field development planning. Accurate measurements of gas viscosity at HPHT conditions are both extremely difficult and expensive. Thus, this fluid property is typically estimated from published correlations that are based on laboratory data. Unfortunately, the correlations available today do not have a sufficiently broad range of applicability in terms of pressure and temperature, and so their accuracy may be doubtful for the prediction of gas viscosity at HPHT conditions.

Use of multilateral wells for oil and gas production has gained strong momentum in the past five years. However, most of the wells do not deliver hydrocarbon fluids at expected flow rates. One of the reasons is that the well planners over-estimate the productivity of wells using inaccurate methods for predicting composite IPRs of well laterals. A more accurate method for predicting composite IPR of multilateral wells is highly desirable. This paper fills the gap. Starting from terms that petroleum engineers are familiar with, a general mechanistic model was developed to combine the fluid flow from individual laterals. The model allows different IPRs of laterals and permits cross-flow between laterals. Pressure losses in both vertical and curvic hole-sections are rigorously considered. Oil and gas wells are treated differently. By combining the composite IPR model with Poettmann and Carpenter correlation, a computer simulator was developed for predicting multilateral well production rate. A case study with measured production rate indicated a 3.1%-error accuracy of the computer model, which is much better than other existing methods. This work provides petroleum engineers a reliable and user-friendly tool for designing and analyzing multilateral wells.