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Electrical Submersible Pump (ESP) lift is extensively used in offshore production systems. Although real-time pump operating parameters and the production data are commonly available according to the recently developed digital energy technologies, the analysis of the acquired data is still insufficient to monitor, diagnose, interpret, and analyze reservoir performance, wellbore integrity, and ESP operating status and efficiency in a real-time manner. Further, the traditional ammeter card diagnosis cannot identify leakage of tubing, underperforming pump lifting, and low pump working efficiency. This paper summarizes typical characteristics of different downhole malfunctions in ESP wells, provides a novel approach to detect those problems systematically and automatically. The developed management system incorporates real-time ESP current data and interpret ammeter card by neural network analysis, which has been trained through over 900 wells. We also derived the analytical solutions for wellhead pressure buildup analysis as a supplement to neural network analysis. Consequently, this model is able to detect downhole problems that cannot be identified by ammeter card. This diagnosis model also sets thresholds for key parameters, and alarm operation team through satellite in a timely manner. This model is a reliable supplementary to the traditional ammeter card diagnosis method, and the online utility provides complement flexibility to cooperate with field operations in real-time. The early-stage identification and resolution of ESP problems can lead to a great cost-saving and less maintenance requirements owing to this intelligent system. This workflow has been successful in field trials.

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.

In the past few decades, Coal-Bed Methane (CBM) has become an important source of energy especially in North America. The methane adsorbed within the coal is in a near-liquid state. The open fractures in the cleats are commonly saturated with water. To develop CBM reservoir, water in the fracture and coal seam must be continuously pumped off from coal seam to reduce pressure and desorb gas from matrix. Although operators desire to produce hydrocarbon quickly, a too fast dewatering rate can irreversibly damage matrix desorption process, which can lead to an unfavorable ultimate recovery. Further, the aggressive production rate can potentially release the coal fines and drive them into pump, which increases maintenance effort and cost. Even worse, the de-watering process fluctuates because of the rock porosity and permeability changes resulting from the brittle coal seam and pressure reduction. Therefore, it is critical to adjust the pump operating parameters in a timely manner to maintain a continuous/intermittent production. Ten CBM wells are located in a remote area, which makes the access to wellsites difficult. Previously engineers had to evaluate well performance and optimize the pump on-site, which is limited by a monthly basis. We firstly developed an automatic data processing system using the advanced Echosounders, which can measure the water level in real time. The reservoir pressure can be then monitored dynamically through interpreting the detected water level. With an automatic-wireless data transferring system installed on-site and a closed-loop control program to receive, process, and interpret data, the pump operating parameters can be changed in real time through remote control. This system not only identifies the downhole problems in real time, but also reduces the pump maintenance frequency from 40 days to 75 days statistically and numbers of trip to well site. Further, the gas production rate has been averagely improved by 30% for the 10 wells. The authors firstly developed an automation data processing and control system in the favor of advanced echosounders. Based on the interpreted reservoir pressure, we can avoid aggressive production by adjusting the pump operating parameters in real time, which eventually results in a better ultimate recovery. The developed workflow (automatic echosounder data acquisition, real filed data transferred to central office, data processing, interpretation, and simulation in computational system, adjustment commands to operating system) is especially valuable for the locations difficult to access.

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.

Pore size distribution is an important parameter in quantifying reservoir heterogeneity. A thorough understanding of different pore sizes in the rock provides a solid base for reservoir development plan and makes an accurate estimation of volumetric sweep efficiency possible. For instance, more certainty in determining pore size distribution can be valuable in accurately predicting the hydraulic flow units which in-turn affects building more reliable geological and petrophysical models for reservoirs. Conventional rock porosity estimation from core and well log only provides porosity without pore size distribution. Therefore methods used to estimate percentages of different pore size are highly desired. Our novel approach is engineered to address this issue. Starting from the capillary pressure data obtained in special core analysis, we developed a correlation in which capillary pressure is expressed as a function of pore size, water saturation, and other petrophysical parameters, which are readily obtained from well log interpretation. Through this correlation each pore size is corresponding to a unique capillary pressure and water saturation. Therefore, the calculation of percentage of each pore size can be accomplished. The pore size distribution from our method is not only vital for two and multiphase flows in reservoirs such as water drive oil and gas drive reservoirs, but also crucial in estimating the percentage of reservoir volume that can be depleted at the abandonment reservoir pressure. Thus a reliable estimated ultimate recovery can be achieved without adding much cost and time since capillary pressure and well log data that are used as inputs for calculation are readily available. Therefore, the proposed method fills the big gap in reservoir characterization and is a useful tool to supplement other methods in reserve evaluation.

Formation damage caused by overbalanced drilling (OBD) using water-based mud (WBM) is inevitable as a result of mud filtrate invading into the near wellbore formation. The invasion radius is critical to the multiphase flow when the well is put on production. It contributes to the total skin that hinders the hydrocarbon production. Furthermore, the response of the logging tools may be affected as a result of such invasion, rendering many inaccurate calculations of the formation evaluation. To evaluate the skin caused by mud filtrate invasion, it is imperative to determine the radius of invasion properly. A thoroughly literature review indicated that the previous investigations have focused on formation damage caused by drilling mud filtration, and none of them had proposed a practical, comprehensive, and reliable method, with solid theoretical base, to quantify this formation damage. This work filled this gap. In this work, we developed a practical and comprehensive model to determine the depth of mud filtrate invasion near the wellbore. The distribution of mud filtrate saturation in the near-wellbore region is also calculated by employing drilling operation parameters, mud filtration test data, relative permeability, and drilling time. With the accurately determined invasion radius, skin factor can be evaluated confidently. Then the well stimulation can be planned accordingly and appropriately, if it is necessary to remove or alleviate formation damage. Therefore, this work is significant in skin calculation and well stimulation design. It can also be used to estimate the cleanup period at the beginning of production, and allows engineers to predict the well performance and diagnose wellbore problems by checking any deviation from the predicted production. This study can also assist with the correction of parameters inferred from log measurements, thereby reducing the over and/or underestimation of log derived parameters used in various formation evaluation calculations.

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.

Maintaining casing integrity, in terms of downhole zonal isolations and well stability, is extremely important in oil/gas wells. Casing wear occurs not only in directional drilling, but also in vertical drilling with a slight deviation angle. In most hydrocarbon wells, deteriorated casing was reported from the onset of casing wear by the presence of friction force during the rotation of drillpipe. The friction force against the casing wall causes the reduction of casing strength. Furthermore, the rotation of drillpipe combined with corrosive drilling fluids could dramatically degrade the casing strength. We used a finite element analysis to focus on the stress evolution in worn casings. Comparison study between worn casing and perfect casing was conducted. Our study showed that the thermal load significantly increases the stress concentration of the worn casing in the wellbore. Finite element solutions indicated that the radial stress of the worn casing is not affected as much as the hoop stress. Along with the increased burst pressure or the elevated temperature, the unworn portion of the casing also suffers from severe compression stress. This work is important to broadening the understanding of well engineers through addressing the true stress profile of worn casing in cemented wellbore.

On October 1, 2008 US DOE-sponsored research project entitled “Geomechanical Study of Bakken Formation for Improved Oil Recovery” under agreement DE-FC26-08NT0005643 officially started at The University of North Dakota (UND). This is the final report of the project; it covers the work performed during the project period of October 1, 2008 to December 31, 2013. The objectives of this project are to outline the methodology proposed to determine the in-situ stress field and geomechanical properties of the Bakken Formation in Williston Basin, North Dakota, USA to increase the success rate of horizontal drilling and hydraulic fracturing so as to improve the recovery factor of this unconventional crude oil resource from the current 3% to a higher level. The success of horizontal drilling and hydraulic fracturing depends on knowing local in-situ stress and geomechanical properties of the rocks. We propose a proactive approach to determine the in-situ stress and related geomechanical properties of the Bakken Formation in representative areas through integrated analysis of field and well data, core sample and lab experiments. Geomechanical properties are measured by AutoLab 1500 geomechanics testing system. By integrating lab testing, core observation, numerical simulation, well log and seismic image, drilling, completion, stimulation, and production data,more » in-situ stresses of Bakken formation are generated. These in-situ stress maps can be used as a guideline for future horizontal drilling and multi-stage fracturing design to improve the recovery of Bakken unconventional oil.« less

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.

With the downturn in natural gas prices, it is vitally important to reduce the cost of drilling shale gas wells. Gas-percussion drilling has been recently employed in shale gas field development. It increases footage capacity by nearly 60%. However, wellbore erosion by the high-velocity gas has been recognized as a problem that hinders further application of the technology. This paper investigates a potential solution to the problem using a new type of flow-diverting joint (FDJ). The FDJ with exchangeable nozzles can be installed at the shoulder of the drill collar to partially bypass gas flow into the annulus between the drill pipe and open hole. Hydraulics computations with a state-of-the-art computer program indicate that this technique will allow for the use of high-gas injection rate to carry drill cuttings while reducing the gas flow rate through the drill bit. As a result, the gas velocity in the drill collar–open hole annulus can be maintained at a safe level to prevent hole erosion. The reduced gas flow rate through the drill bit also minimizes wellbore enlargement at hole bottom. Sensitivity analyses with the computer program show that the FDJ-nozzle area to bit-nozzle area ratio is directly proportional to the annulus area ratio, and the bypassed flow rate fraction remains constant as drilling progresses. This makes the FDJ system easy to design and practical to use over a long section of hole to be drilled.

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.

Abstract Forchheimer equation takes non-Darcy flow effect into account in the event of high flow velocity in porous media. Its application requires both permeability, which is in linear term, and Beta factor, which is in quadratic term. Permeability and Beta factor are determined by rock type, textural of rock, effective porosity, pore throat size, geometry of the pore, and connection and distribution of pores. Beta factor comes into play when the fluid flow rate is high and the flow rate deviates from Darcy's law. Non-Darcy flow is described by Forchheimer equation. Usually the coefficient of non-Darcy flow term is hard to be determined. Existing approaches are core measurement and empirical correlations. To the best of our knowledge there is notheoretical equation available. To get an accurate estimation of flow rate or pressure drop in the reservoir, we need a method that has solid theoretical basis. The deficiency triggered our study. Starting from multiple-capillary tubes concept, we derived a rigorous relationship between pores geometry and pressure drop required for fluid flow through the pores. Through this correlation pressure drop can be calculated from known pores geometry. Since pores geometry can be often obtained from lab experiment or well logging, the new correlation also provides a unique approach to quantify the coefficient of quadratic term in Forchheimer equation. In this study we developed a governing equation through a rigorous theoretical derivation. With this equation the non-Darcy flow coefficient in Forchheimer equation can be calculated. The required input data for the new equation are readily obtained from well log interpretation. The new equation is a powerful tool in the event of no experimental measured non-Darcy flow coefficient available. It eliminates the errors or the arbitrary content in the empirical correlations.

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.

Production and injection forecasts are of significance in terms of constructing infrastructure to accommodate the booming of unconventional oil and gas development and production in Williston Basin in North American (United States part). Underestimate or overestimate of future production will lead to an inappropriate plan of infrastructure development in this geographic area. Insufficient infrastructure will slow down the growth of hydrocarbon development and affect the revenue from fossil energy and the United States' (U.S.) energy security. Oversized infrastructure will result in waste of investment and leaving large footprint that impacts the environment significantly. Conventionally, production forecast is conducted at well or field level. A thoroughly literature review indicates that no study is available to predict the production of unconventional resource at basin level. To fill this gap, we propose a procedure to forecast the total production of a basin. Our study provides a guideline for forecasting production in a basin with similar geological settings.

The Bakken formation is a tight oil play with continuous oil accumulation. Fractures play an important role in both exploration and production of the oil. As considered to be one of the most promising plays in the world, oil production from the Bakken largely depends on presence of natural or artificially-created fractures. There also exist arguments about the oil migration patterns in and out of the Bakken. This paper reviews the tectonic history of the Nesson anticline in the Williston basin, North Dakota, USA, and a numerical model of the study area has been built to reconstruct the paleostress under the far-field effect of the Laramide orogeny in late Cretaceous. The modeling results show that tensile horizontal stress was developed in most parts around the Nesson master fault in the study area during the Laramide event, and tensile fractures are very likely to be generated in the north and south sides of the fault. These tensile fractures could enhance the reservoir quality in both porosity and permeability. Zones of possible fracture development are identified based on the stress profile. In the fault zone, the paleostress has a lower magnitude of compressive stress than that in the host rock, so driving force may be provided to push the oil migrate from the host rock to the fault zone. However, after the hydrocarbon accumulated in the fault, fractures presented around the fault may function as additional pathways for migration again.

The 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 Buckley–Leverett method was used to analyze waterflood project directly without any adjustment based on the real reservoir and production situations. By doing so, errors are introduced into the analysis. Buckley–Leverett method assumed that 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 and 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.

High-pressure and high-temperature (HPHT) gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300°F. 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. This paper reviews the databases of hydrocarbon gas viscosity that are available in the public domain, and discusses the validity of published gas viscosity correlations based on their applicability range. A falling body viscometer was used in this research to measure the HPHT gas viscosity in the laboratory. The instrument was calibrated with nitrogen and then, to represent reservoir gas behavior more faithfully, pure methane was used. The subsequent measured data, recorded over a wide range of pressure and temperature, was then used to evaluate the reliability of the most commonly used correlations in the petroleum industry. The results of the comparison are presented here and suggest that at pressures higher than 8000 psia; the laboratory measurements drift from the National Institute of Standards and Technology (NIST) values by up to 7.48%. Finally, a sensitivity analysis was performed to assess the effect of gas viscosity estimation errors on the overall gas recovery from a synthetic HPHT reservoir, using numerical reservoir simulations. The result shows that a −10 % error in gas viscosity can produce an 8.22% error in estimated cumulative gas production, and a +10% error in gas viscosity can lead to a 5.5% error in cumulative production. These preliminary results indicate that the accuracy of gas viscosity estimation can have a significant impact on reserves evaluation.