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Previous researches focused on dry sample thermal treatment to enhance rock permeability indicate that thermal treatment can be a novel stimulation technique for geothermal and hydrocarbon reservoirs development. The mechanicm of thermal permeability enhancement depends on the generation of microcracks by thermal cracking. In this study, chemical solutions were introduced on sandstone rock samples and observed that they can be used to control thermal permeability enhancement. Sandstone specimens with the same order of permeability were saturated with different salt solutions and heated to different temperatures. The results quantify permeabilities and porosities of specimens saturated with electrolyts over them without chemical treatment but heated to the same temperature. The KCl solution had the largest effect on permeability enhancement for the tested rock and showed a tenfold increase in permeability, and followed by NaCl and K2CO3 solutions. However, CaCl2 solution and distilled water had negative effects. Laboratory results also revealed a positive correlation between some chemical concentration with the permeability increment of rock. The effects of electrolyte type and concentration on thermally permeability enhancement of the tested rocks were determined and a statistical model was fitted. The results show that the permeability increment follows an exponential growth with temperature when the rock was heated over the threshold temperature of thermal cracking. Introducing specific chemical species into a low-permeability formation and heating the formation beyond the threshold temperature of rock thermal cracking will be a promising way to further enhance formation permeability.

The well performance in Coal-Bed Methane (CBM) reservoir is highly dependent on the conductivity of hydraulic fracture created to increase well production rate and contact area with the reservoir. Aimed at improving the effective fracture length of hydraulic fracture in CBM reservoir and the seam proppant concentration, the objective of this paper is to investigate the migration of variable density proppant particles in hydraulic fracture and seams using numerical modeling and simulation. In the proposed model, the interaction among fracture proppant particles distributed in a pseudo fluid model is taken into consideration. Comparison between the model calculation and field radioactive tracing logging interpretation shows that the proposed model is accurate and reliable in applications. Additionally, we carried out the sensitivity study on the viscosity of fracking fluid, fracture area, proppant density, injection rate and other factors. It is shown that, with the condition of a confining pressure of 69 MPa and an ambient temperature of 90 °C, the crush value of nutshell proppant is less than 2%, which meets the field application requirements. Furthermore, with the increase of both fracturing fluid viscosity and injection rate, the propped effective fracture length increases, and lead to a more uniform distribution of proppants. The increase in proppant particle diameter, inversely, results in a decrease in the effective fracture length. As for variable-density proppant, the effective crack support length would be longer than the single ceramic proppant, and the particle distribution of the case with variable density is more uniform.

Summary On the basis of the wellbore and reservoir heat-transfer process during deepwater drilling, a heat-transfer model between wellbore and formation is built up for two different conditions: without riser and with riser. Wellbore and formation temperature distributions under different drilling-fluid-injection temperatures, flow rates, circulating times, and drilling depths are simulated by use of this model. Taking the hydrate-phase equilibrium into consideration, a possible region of hydrate-formation dissociation is analyzed, and effective methods are proposed to control the hydrate dissociation. The results indicate that, during shallow formation drilling, the increase of drilling-fluid flow rate will cause the wellbore temperature to rise, but below the hydrate-dissociation temperature in the whole process; during deep-formation drilling, drilling fluid is heated, and the heat is transferred from the deeper formation to the shallower formation through fluid circulation. Thus, the hydrate-reservoir temperature increases gradually along the wellbore radial direction. Hydrates will dissociate after the hydrate equilibrium temperature is reached; this may cause wellbore collapse or methane leak from the reservoir and result in disaster. To control hydrate dissociation during deepwater drilling, attention should be paid to the period of deep-formation drilling. Sensitivity studies indicate that the risk of hydrate dissociation rises as the drilling-fluid-injection temperature, flow rate, and circulating time increase.

Summary Hydraulic fracturing has been applied as an effective method to increase gas production from shale formations; however, this method has also raised concerns about its adverse impacts on environment. For example, in the Marcellus shale formation, some measured radon-gas concentrations exceeded the safe standard. Therefore, it is important to quantitatively evaluate radon concentration from fractured wells. However, existing researches have not successfully conducted a systematic and predictive study on the relationship between shale gas production and radon concentration at the wellhead of a hydraulically fractured well. To address this issue and quantitatively determine the radon concentration, we present the mechanisms of radon-gas generation and releasing, and conducted numerical simulations on its transport process in the subsurface formation system. The concentration of radon in produced gas is related with the original sources where the natural gas is extracted. Radon, generated from the radium alpha decay process, is trapped in pore spaces before the reservoir development. With the fluid flowing through the subsurface network, released radon will move to surface with the produced streams such as natural gas and flowback water. Our study shows that the radon concentration at wellhead could be significant. Influential factors such as natural-fracture-network properties, formation petrophysical parameters, and fracture dimension are investigated with sensitivity studies through numerical simulations. Analysis results suggest that radon wellhead concentration is strongly related with production rate. Thus, careful production design and protection are necessary to reduce radon hazard regarding the public and environmental impact.

Hydraulic fracture geometry is of the interest in optimizing stimulation treatment and forecasting production potential. Current diagnostic tools such as tiltmeter and microseismic are insufficient in evaluating fracture geometry. Knowing that gas from the shale reservoir has a much higher mobility than fracking fluid, partitioning chemical tracer is employed so that tracer data can be obtained earlier and more complete. The proposed approach is examined by synthetic numerical simulations. On the semi-log plot, tracer production declined tail clearly divides into two straight-line segments. Applying the moment of methods to the entire tracer production data gives the total volume of hydraulic fracture and the invaded matrix swept by the tracer due to leak-off. Additionally, extrapolating the first segment of tracer decline tail using the exponential law yields a volume that is close to the actual hydraulic fracture volume, especially when fracture permeability is several orders larger than matrix permeability.

Carbon dioxide capture, utilization and storage (CCUS) is an important technology to combat global climate change. Carbon dioxide (CO 2 ), a greenhouse gas, can also be used to extract lighter components from subsurface fluids in a multicomponent hydrocarbon system. In many oil and gas bearing basins, there are high temperature and high pressure aquifers saturated with methane. These aquifers are usually known as geothermal-type water-soluble gas reservoirs. The geothermal-type water-soluble gas reservoirs have great potential for coupled development to harvest thermal energy and natural gases. Additionally, the aquifers can serve as favorable sites for CO 2 geological sequestration. This paper proposes a new feasible technology that combines CO 2 geological sequestration with geothermal-type water-soluble gas recovery (CO 2 -GWSGR). This proposed technology injects CO 2 into the pressurized aquifer for greenhouse gas reduction and natural gas and thermal energy development. In the Yinggehai Basin, there are rich water-soluble gas resources and some natural gas wells that produce CO 2 . Based on the reservoir characterization of the Yinggehai Basin, a 3-D conceptual model was designed and simulated using the TOUGH2/EOS7C program. Simulation results show that CO 2 injection can effectively enhance recovery of water-soluble gas. Sensitivity studies indicate that CO 2 storage and energy production increase with the increases in well spacing and reservoir thickness. Numerical simulation was used to model the impact of factors such as reservoir heterogeneity and injection fluid on thermal energy recovery and CO 2 storage. Simulation results show that the economic revenue per ton of CO 2 storage under injecting fluid with the dissolved CO 2 is approximately 18 times greater than that of injecting pure CO 2 . This revenue will offset the capture and storage costs of CO 2 to a large extent. Considering the economics and the escape risk of carbon dioxide in aquifers, injecting fluid with the dissolved CO 2 is the best injection method. The results of CO 2 -GWSGR technology provide new perspectives and valid technical references for geothermal-type water-soluble gas production and carbon dioxide storage.

Characterized by rock sediments and complicated storage mechanisms, shale reservoir development is to create flow systems comprised of complex natural fissures and hydraulic fracture stimulation such that the hydrocarbons in the reservoir can be recovered economically. The prediction of shale reservoir production performance is critical for reservoir management and challenging due to the compounding nature of multiple flow mechanisms one encounters during the life of a shale gas well. Given empirical nature, many models based on curve-fitting historical production data prone to inaccurately forecast well's rates in shale gas reservoirs, particularly when the production history of a well is short. This paper further extends the applicability of the Connected Reservoir Storage Model (CRSM) to shale reservoirs. The CRSM was derived from diffusivity theory by using historical production rate and bottomhole flowing pressure (BHFP) to determine the reservoir behavior and unit pressure response, and it can be conveniently used to predict production performance under variable operating conditions. The CRSM is mathematically robust and easy for application since it can be determined with limited reservoir information without knowing the reservoir geometry or reservoir permeability. This study uses the operational history of a shale gas well to demonstrate the CRSM's capability in rate prediction and couples the model with stochastic methods to approximate the most probable outcome under variable operating conditions.

Horizontal drilling and hydraulic fracturing enabled the extraction of hydrocarbon from tight formations in countries such as the United States, China, and Argentina. Some factors such as stress anisotropy, formation temperature and quantity of natural fractures are reservoir specific and should be considered in the completion design; otherwise, high rates and pressures applied during hydraulic fracturing in a long horizontal section could induce wellbore integrity issues. Based on field parameters, we studied how the integrity of the cement and casing is affected during these operations using finite element analysis (FEA) to study the stress concentration in casing and cement. The yield criterion of equivalent von Mises stress was applied in order to verify if the stresses were exceeding the casing yield strength and the cement compressive strength. Simulation results revealed that a poor centralization that contributes to the formation of drilling fluid voids in the cement will induce casing failure during hydraulic fracturing operations. The equivalent maximum stress can increase from three to four times in casing and cement from a concentric case to an eccentric case in a cement sheath with voids.

Formation damage, caused by inorganic deposition, mainly results from the precipitation of scales in the formation when reservoir conditions change or multiple incompatible streams of fluids mix. Solid-scale precipitation often occurs during waterflooding processes in which the injected water mixes with formation water in the formation. The management of scale and reducing scaling risk are multidiscipline tasks and this is something the industry struggles with. The risk of inorganic deposition has a higher impact on production facilities such as wellbore, pipeline, and separators than formation damage in the reservoir; however, this chapter is focused toward scaling in porous media, especially regions surrounding the wellbore. For convenience, inorganic depositional matters and scales are used interchangeably in this chapter.

High investment and costly operation require that deepwater wells produce at as high a rate as possible. Therefore, a variety of technologies have been used to remove the production barriers and push the production limits. On the other hand, any previous discussed formation damage mechanisms could happen in the deepwater environment. In this chapter, we present the difference that water depth makes, intelligent well surveillance and completion, frac-pack well completion, formation damage because of compaction, and other problems featuring in deepwater development. The objective of this chapter is to present the uniqueness of offshore development and production in the terms of formation damage and remediation.

Temperature measured from a permanent downhole gauge in a well after the well shut-in provides a unique perspective for surveillance and production management. For example, in deepwater environment, production engineer needs to know the temperature of a shut-in well before it is being restarted since different temperature profiles along the wellbore may need very different restarting strategies for flow assurance purpose. A number from the “rule-of-thumb” or running complicated numerical simulation is either not reliable or impractical. This paper presents a semi-analytical model to estimate the temperature transient behavior after the well shut-in. The temperature at a point along the wellbore, which is useful for production management and flow assurance, is solved and the solution can be easily implemented for calculating temperature history. The temperature profile solution for locations along the wellbore is also presented in the paper. Furthermore, matching the calculated temperature with the measured temperature at the same location will yield the well local heat transmissibility coefficient. The applications of the solution to this model are multiple folders and a deepwater field example is provided to demonstrate some applications and valid the results.

The ultimate recovery factor is strongly affected by petrophysical parameters, engineering data, structures, and drive mechanisms. The knowledge of the recovery factor is needed for multiple decision makings and it should be known in the whole development process. This study is to estimate the recovery factor from a different perspective with traditional methods. Using development data from the Gulf of Mexico, this study explores parametric relationships between different reservoirs using data analytics. Given that there are hundreds of attributes to characterize a reservoir, and some of the records in a database may not be accurate or contradictory to each other, we use dimensionless parameters to categorize reservoirs based on similarity theorems. Using dimensionless parameters not only reduces the number of variables for data analytics, but they have physical meanings which make them easily applicable to different scenarios. This research presents a comparative study of different data mining techniques and statistical significance of various geological, reservoir and engineering parameters. This dataset consists of 4000 oil reservoirs and each reservoir has 82 attributes. Initial data cleaning was carried out on this dataset to remove reservoirs with erroneous data entries. Dimensionless reservoir parameters are defined and used for the study to make the models consistent to other reservoirs. In the model development, 80% dataset was used to train the model and the rest dataset was used to evaluate the trained models. A few models based on their intrinsic design predicted the ultimate recovery factor with an error of 8-9%, and a few other models predicted the same with an error of 10-12%. Ensemble of a few models predicted oil recovery factor with an error of 6%. In addition to predict ultimate recovery factor, relative importance of various dimensionless parameters, and sensitivity of ultimate recovery factor to reservoir and engineering parameters were studied. This kind of study uses already available reservoir data and model to provide a quick means to evaluate new oil reservoirs even with limited data.

The characterization of hydraulic fractures is critical in well performance evaluation and production forecast. In practice, many inverse methods such as tracer analysis, micro-seismic and acoustic sensors are applied to quantify the geometry of the created fractures. Unlike the above methods that involve additional measurements, this study focuses on the water production by studying their flowback volumes, chemistry and their relationships with fracture characteristics. In this study, the flowback water data are used to analyze hydraulic fractures' characteristics. According to the flowback water analysis for hydraulically fractured wells in Marcellus based upon ion mass transport, it is easy to notice that, in most cases, fracture network with smaller apertures generates lower water recovery and higher flowback ions concentration simultaneously, and vice versa. By study the flowback water, the average width of fractures can be roughly estimated.

Summary Permanent downhole-pressure and -temperature gauges have been installed in many intelligent wells worldwide, providing high-resolution and precision surveillance data about the performance of wells and reservoirs. Compared with the pressure data, the temperature data have been underused in the petroleum industry. In this paper, we first examine the measured downhole-temperature variation caused by the Joule-Thomson effect and infer the true reservoir temperature and the skin history from the temperature data. An analytical relationship between the temperature data and the skin is presented. Through the use of this relationship, many purposeful surveillance studies, such as monitoring the skin change of the well, can be conducted. Examples of such studies will be provided and discussed using some deepwater-field data. Furthermore, the downhole temperature can be used to detect whether water breakthrough occurs by means of matrix or fracture through use of the thermal retardation factor. When coupled with the production data and pressure-falloff (PFO) tests, the downhole-temperature data can be used to estimate the water-breakthrough time. The application of this analysis is of practical interest for subsea-well development because of the prohibitive costs and high risks of production logging.

The p/z plot of an overpressure gas reservoir with a closed boundary typically is a downward concave curve. Overestimation of the original gas in place (OGIP) caused by incorrect extrapolation of the early production data is often observed in reserve evaluation. To eliminate this error, a comprehensive compressibility term that includes pore volume compressibility, water compressibility, and gas solubility in water has been introduced into the p/z plot. To achieve the above objective, it is critical to obtain the right average reservoir pressure corresponding to the drained gas reserve at the time of interest. But for overpressure gas reservoirs, if we completely ignore the permeability changes as the reservoir pressure declines, the reservoir performance will not be representative. Another substantial deficiency of the conventional method is that the solution gas in connate water has been 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 missing terms lead to an inaccurate estimation of the OGIP and gas reserve. Considering that the permeability is not constant throughout the reservoir life, but a function of pressure, rock and fluid properties, production volume, and original pore volume, we present a new form of MBE which includes the effects of the permeability change due to pore volume change 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 more accurately estimated. Therefore, the evaluations of OGIP and recoverable gas are more reliable.

Excessive water production from hydraulically fractured unconventional reservoirs is historically considered as burdensome liability in terms of costly treatment and disposal. However, this paper demonstrated produced water as a valuable asset, which is capable of producing geothermal energy, and it can actually help offset the operation costs for unconventional oil and gas producers. Harnessing geothermal energy of produced water for power generation from unconventional horizontal wells features significant advantages over traditional geothermal wells, especially in reducing capital expenditure and operational risks. This paper proposed a novel design of downhole power generation in horizontal wells by integration of thermoelectric technology with hydrocarbon production. In the design, we retrofit the horizontal wellbore to circulate cold water inside the tubing so that a cold temperature interface can be created. The produced fluids flow through the annulus of the tubing and casing to maintain hot temperature on the side of tubing. By attaching thermoelectric generators (TEG) on the outer surface of tubing, this retrofit will make it possible to capture subsurface in-situ geothermal energy of the produced fluid and directly transfer heat to electricity inside the horizontal wellbore. Furthermore, we also built the mathematical model to account for the heat conduction and convention in the wellbore and surrounding formation, which could accurately simulate the temperature distribution and power generation under variable operational conditions. Based on the model, we identified the key parameters with significant impact on power generation and established the well section criteria for best power generation performance. To discover the potential of power generation in horizontal wells, we conducted a case study in Daqing Oilfield in northeast China and compared the power generation performance with vertical well with same TVD and same power generation device installation. The results of case study indicated that horizontal well displayed exceeding power generation performance over vertical wells. In practice, this paper could contribute to enrich geothermal development methods and provide the guidelines for oil and gas producer to evaluate their horizontal assets and identify the opportunity to capitalize on geothermal power generation from horizontal wells.

CO2 flooding is an important method for improving oil recovery for reservoirs with low permeability. Even though CO2 could be miscible with oil in regions nearby injection wells, the miscibility could be lost in deep reservoirs because of low pressure and the dispersion effect. Reducing the CO2−oil miscibility pressure can enlarge the miscible zone, particularly when the reservoir pressure is less than the needed minimum miscible pressure (MMP). Furthermore, adding intermediate hydrocarbons in the CO2−oil system can also lower the interfacial tension (IFT). In this study, we used dead crude oil from the H Block in the X oilfield to study the IFT and the MMP changes with different hydrocarbon agents. The hydrocarbon agents, including alkanes, alcohols, oil-soluble surfactants, and petroleum ethers, were mixed with the crude oil samples from the H Block, and their performances on reducing CO2−oil IFT and CO2−oil MMP were determined. Experimental results show that the CO2−oil MMP could be reduced by 6.19 MPa or 12.17% with petroleum ether in the boiling range of 30−60 °C. The effects of mass concentration of hydrocarbon agents on CO2−oil IFT and crude oil viscosity indicate that the petroleum ether in the boiling range of 30−60 °C with a mass concentration of 0.5% would be the best hydrocarbon agent for implementing CO2 miscible flooding in the H Block.

Summary Permanent-downhole-gauge (DHG) technology has been used widely in deepwater-reservoir development in the last decade and is playing an increasingly significant role in real-time reservoir/well surveillance and management. Tidal signals extracted from this 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 have treated tidal signals as pressure "noise," and little has been discussed on how to use tidal information in reservoir characterization. This paper will address how to use the fast Fourier transform (FFT) to extract tidal signals and the theories and methods for processing the signal to achieve reservoir characterization. In addition, a couple of examples from a deepwater field will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid-saturation change, and detect the presence of a secondary gas cap. This paper will show that FFT is a fast and reliable method for processing the DHG pressure data for tidal signals that can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signals are unique because they cannot be obtained in the laboratory, by simulation, or by direct measurement because of the scale affected by tides.

Summary The significance of setting optimal surface separation pressures cannot be overemphasized in surface-separation design for the purpose of maximizing the surface liquid production from the wellstream feed. Usually, classical pressure volume-temperature (PVT) analysis of reservoir fluids provides one or several separator tests through which the optimum separator pressures are estimated. In case separator tests are not available, or the limited numbers of separator tests are not adequate to determine the optimum separator pressures, empirical correlations are applied to estimate the optimum separator pressures. The empirical correlations, however, have several disadvantages that limit their practical applications. In this study, we approached the problem with a rigorous method with a theoretical basis. According to the gas/liquid equilibrium calculation, the optimum separator pressures were determined. Comparisons of our results with experimental data indicated that the proposed method can simulate the separator tests very well. Because the method has a theoretical basis and does not require existing two-stage or multiple-stage separator-test data as in the application of empirical correlations, it potentially has wide applications in practice for a variety of conditions and yields a more optimal separation scheme than the empirical correlations. Furthermore, the method is independent of reservoir fluid. In the event that separator tests are available from fluid analysis, our method can be used as a quality-control tool. Because the setting for optimal separation pressures vary as the composition of the wellstream changes during the field life, our method provides a quick and low-computational-cost approach to estimate optimum separator pressures corresponding to different compositions.

According to the requirements of rapid setting at low temperatures and long-term performance during high-temperature production on cementing for heavy oil thermal recovery wells, this study proposes the application of aluminate cement to cementing of heavy oil thermal recovery wells. Against the background of operation conditions in Liaohe Oilfield, the strength decline mechanism of the conventional silicate cement stone added silica sand were evaluated by simulating the high-low temperature circulating humid environment that the cement sheath of the heavy oil thermal recovery well faced with. Then, through laboratory experiments, the research compounded a kind of mineral clinker based on aluminate cement, prepared fluid loss agent J73S and retarder SR compatible with aluminate cement and designed a new-type thermostable aluminate cement slurry system with an applicable density range of 1.70g/cm3~1.90g/cm3 and temperature range of 30°~80°. Moreover, the hydration product and the thermostable mechanism of the modified aluminate cement slurry were analyzed through this simulation. According to the results, with the crystalline transforming at high temperatures, the strength of conventional silicate cement with silica sand substantially declines under the condition of multi-cycle high-low temperature circulation, therefore it cannot satisfy the cementing requirement of thermal recovery wells effectively. The thermostable aluminate cement slurry system features excellent engineering performance: the slurry density difference is lower than 0.02 g/cm3, the fluid loss is less than 50 ml, the thickening time is adjustable from 60 min to 300 min, the 24h strength is up to 14 MPa, and the compressive strength of cement slurry can still reach 25 MPa after two rounds of high-temperature testing. In addition, the SiO2 in the additives massively participate in the hydration reaction, endowing the modified aluminate cement slurry with favorable thermostable performance and long term stability. The application of the cement slurry system to cementing for heavy oil thermal recovery wells of Liaohe Oilfield exhibits a smooth operation process and excellent cementing quality, so it can efficiently satisfy the cementing operation requirement of heavy oil thermal recovery wells efficiently.

Summary Because of its efficiency, cleanliness, and reliability, natural gas is an important sector in global energy consumption. It supplies nearly one-fourth of all energy used in the United States and is expected to increase 50% within the next 20 years. More gas-delivery infrastructure is being constructed to meet the transportation requirement of the ever-increasing demand for natural gas, while at the same time, the existing gas infrastructure is aging. Ensuring natural-gas-infrastructure reliability is one of the critical needs for the energy sector. Operators prefer to capitalize on the transportation capacity of these old pipeline systems to reduce the cost for building new pipelines, but they run a high risk of encountering partial blockage in the pipeline, which can cause operating pressure to exceed the safety specification. Therefore, the reliable and timely detection of a partial blockage in a gas pipeline is critical to ensuring the reliability of the natural-gas infrastructure. To design proper pigging tools, it is important to detect the location and size of partial blockages. Physical inspection and mathematical-model simulation are used to identify partial blockage in gas pipelines. Generally, the physical method can result in an accurate detection of the location and size of the partial blockage, but at the expense of production shutdown and high cost/long time to run the physical detection, which is a very expensive measure in a long-distance gas pipeline. The mathematical simulation detects partial blockage through numerical modeling, which could provide a quick evaluation at a much lower cost, but with higher uncertainties. Our literature review indicates that a simple, practical, and reliable method to detect partial blockage without a recorded inlet or outlet pressure is in great demand. In this study, we develop a multirate test method to detect partial blockage in a gas pipeline. By conducting multirate tests, the location and size of the partial blockage can be evaluated. The new method can be applied under the conditions of no measured inlet or outlet pressure, which have not been investigated before. It is worth locating a partial blockage under these conditions because as oil and gas exploration and production move to harsh environments, no pressure gauge being installed at the inlet or outlet of the pipeline can be a common circumstance in the fields. Even for onshore fields or fields with easy access, pressure is not transferred to the central office in real time. In addition, the metering equipment and pressure gauges installed in the pipeline may not be working. Therefore, our method provides a practical, quick, and low-computational-cost approach to estimate partial blockages corresponding to these conditions. The partial blockages in a single pipeline and in parallel/looped pipelines were evaluated in this project by use of the proposed method. Considering that most of the complicated pipeline systems under operation can be decomposed into basic units, such as single pipeline and parallel/looped pipelines, the proposed model can realistically and feasibly identify partial blockage in a complex pipeline network. Furthermore, existing studies assume only single partial blockage in the pipeline, which limits the application of available models because the detection will be misleading if there is more than one partial blockage in the pipeline. To fill this gap, we developed a model to differentiate the single-partial-blockage scenario from the multiple-partial-blockage scenario on the basis of multirate tests. The identification is critical because it guides partial-blockage detection in the right direction.

Summary Subsea processing is an evolving technology in response to ultradeepwater hydrocarbon development and has the potential to become one of the most attractive methods in the oil industry to economically unlock hydrocarbon resources. The objective of this paper is to examine the features of subsea fluid-processing technologies and capabilities, and compare the advantages and disadvantages of different facility types. The advantage of subsea processing systems is that they allow fluids to be boosted from longer tieback distances. Constraints associated with subsea processing systems include operation efficiency, produced-water and sand-handling capabilities, and the system’s ability to handle hydrates/scale. In this paper, we reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each. Furthermore, future subsea-technology development and anticipated challenges are outlined in this paper. The significance of this study is to summarize the lessons learned from current available uses so that future decisions regarding the application of these subsea processing technologies can be made appropriately and efficiently.

The objective of this paper is to integrate "Big Data" concept with petroleum engineering knowledge for the prediction of recovery factor in Deepwater Gulf of Mexico (dGOM) oilfields. Recovery factor is affected by many geological and engineering factors; as a result, there is no explicit approach to accurately calculate the recovery factor. This is particularly true for deepwater development as the parameters associated with the recovery factor estimation have significant uncertainties and usually extremely costly to obtain. Typically, the recovery factor of a field is estimated using analogs, material balance, decline curve or numerical simulation. These deterministic approaches requires representative geological models. However, enough information is often not available to capture the realistic flow. In addition, the estimated recovery factor can be very different using different methods. Reservoir engineers are faced with the challenging task of estimating recovery factor by optimizing a large number of parameters with limited, sometime inaccurate information. This dilemma calls for an alternative approach in handling the noisy data. Data mining and classification identify hidden patterns in unstructured data and tend to be fairly robost in the presence of noisy data. Using a database of 395 Deepwater Gulf of Mexico (dGOM) oilfields with 84 attributes, a set of dimensionless numbers are calculated for 59 oilfields with water drive. This helps in dimensionality reduction and scaling of reservoir models for comparison. Based on the distribution of dimensionless numbers, data mining techniques like K-means clustering followed by principal component analysis (PCA) are used for classifying oilfields into four categories. Subsequently, partial least square (PLS) regression is used for relating dimensionless numbers to recovery factor from sparse data in dGOM, which gives good coefficient of correlation for some clusters. This paper shows that dimensionless numbers together with data mining techniques provides a new, easy to implement method for predicting recovery factor for large datasets where application of other methods are limited due to requirement of high computational cost and time.

Chemical tracer is an alternative technique for hydraulic fracture diagnosis other than tiltmeter and microseismic mapping. Fracture volume is an essential parameter for stimulation optimization and production forecast. In our previous work, we proposed a simple, cost-effective method to assess the fracture volume using partitioning chemical tracer. In the hydraulic fracturing stage, a partitioning chemical tracer slug is injected along with the fracking fluid. In the created hydraulic fracture, the tracer partitions in both vapor and liquid phases and flow back in the production stage. By analyzing the tracer production data, we could estimate fracture volume and leak-off volume. This work will first investigate chemical tracer selection criteria for the purpose of fracture volume diagnosis. Tracer partition coefficient and tracer adsorption are the main considerations. Our results suggest a careful section is needed for partition coefficient, balancing the estimation accuracy and investigation area. In addition, the selected tracer should have negligible adsorption. Numerical simulation is another way to interpret tracer test. In the second part of this paper, we propose a modified Random Walk Particle Tracking (RWPT) algorithm to simulate the partitioning chemical tracer transport with multiple mobile phases. Output obtained through the RWPT is identical with analytical solution and its tracer critical breakthrough time is more accurate than the result from the finite-difference based simulations.

Carbonate reservoir with low permeability is developed using fracturing technology to effectively stimulate the reservoir for a higher productivity. However, as the carbonate reservoir features extreme heterogeneity, not every fracture is created equally as is obtainable through acidizing fracturing or using proppant. The objective of this study is to help make the decision among acid fracturing or proppant fracturing, to achieve an economically and operationally feasible treatment through extensive research of field cases on critical factors and numerical simulation. An ideal fracturing method of a carbonate reservoir should yield a high conductive fracture with a potential for long production duration under depletion scenario within an economic limit. We first review real field cases to identify critical parameters affecting fracture geometry and productivity; then we validate and quantify their individual effectiveness using 3D synthetic models with numerical simulation. In the simulation work, both treatments are evaluated by simulating the production of the reservoir for 1,500 days post treatment. Results are compared for different reservoir parameter variations including porosity, permeability, temperature, depth and young's modulus. Simulation of the field is continued for 1,500 days after the treatment to see the effect of the production enhancement for both types of treatment. This is also done to include long term loss of fracture conductivity and its effect on the overall production. Fracture geometry from each case is also analyzed and compared to the base case scenario. Even though hydraulic fracturing and acidizing technologies have been the dominant stimulation methods in unconventional resources and many variants have been developed, there is still no well-defined guideline which can help an operator to select the stimulation techniques suitable for their particular fields. This paper focuses on factors influencing decision making on the stimulation of carbonate reservoirs based on reservoir characterization. The advantages and limitations of proppant fracturing and acid fracturing are compared based on field applications, which can enable an operator to make quick and informed decision on which stimulation should be used. Numerical effort confirmed and quantified our observations. Comparisons have been drawn on different types of proppant and acid treatments and their effectiveness on the target reservoir. The study eventually comes up with identifying main factors of reservoir for treatment selection and recommendations are presented from these findings that which type of reservoir is best suited for which type of treatment. The novelty of the study is summary of previous field cases with a clear guideline on making decision in carbonate reservoir stimulation. As a further extension to this study, PVT data can also be included to see the extent of reservoir fluid change effect on the outcome of the treatment.

Petroleum exploration and production from Bakken and Three Forks formations in Williston Basin have achieved great momentum since 2005. To overcome the resistance of the low to extremely low permeability to hydrocarbons flow from reservoir to bottomhole, horizontal wells with multistage fracturing completion are applied to gain economical rate. Currently, horizontal lateral lengths that exceed 10,000 feet with more than 50 stages are not uncommon in Williston Basin. Field experience and practice indicate that different stage intervals usually results in different estimated ultimate recovery (EUR). Therefore, it is worth to identify optimal stage interval to stimulate horizontal lateral to cut costs through using the appropriate volumes of fracing fluid and proppant and to maximize profit by improving EUR. It should be noted that production from horizontal well with multistage fracturing is not only impacted by several factors such as geological characteristics, lateral length, orientation of horizontal lateral, fracing fluid, proppant, stimulation operating and procedure, and fracturing stage interval, but also by their interactions. To make the analysis reasonable, normalization analysis is exploited to differentiate the influences of different parameters. Sensitivity analysis of individual variable is applied to evaluate its influence on production. The analyses give a range of optimal stage interval for Bakken and Three Forks formations in different fields in Williston Basin. Considering the fact that variations in geology lead to different optimal stage intervals, it is appropriate to use a range instead of a single number as a reference in the well design. Although the results are derived from Bakken and Three Forks formations, the findings in this study can be employed in reservoirs with similar geological characteristics and reservoir properties. This study also identifies optimal ranges for operational parameters such as treatment pressure gradient, pumping rate, sand-to-water ratio, fracing fluid volume/length, and proppant mass/length, which are crucial to the cost reduction and operation efficiency.

Enhanced oil recovery techniques are having a growing interest for unconventional reservoirs to attack the low primary recovery factor issue, especially in a low oil price environment. Tight oil behaves a quick decline without much pressure support and thus jeopardies project profitability given a large initial capital requirement for horizontal drilling and massive multi-stage hydraulic fracturing operations. However, over 90% oil is still left behind in stimulated reservoir volume. It is imperative to understand the differences in production drivers in unconventional reservoirs, especially using EOR techniques, for example, how capillarity and adsorption may greatly alter phase behavior in nano-size pores. Previous studies showed that phase behavior and production mechanisms might be significantly different under nano-scale pore confinement in organic matter in Eagle Ford formation. This research was to shed light to quantify such differences under the influce of large capillary forces in organic and inorganic pores integrating petrographic and/or petrophysical measurements, for example, mercury injection capillary pressure (MICP) experiments. Further, this study developed a new methodology to consistently evaluate the effect of adsorption at the same pore size distribution as capillary evolved. Results showed that a large difference of phase and adsorption behavior existed for unconventional reservoirs in the oil window in the Eagle Ford formation, and pore size distribution played an important role in quantifying such differences. This may lead to additional rock-typing techniques to better characterize the Eagle Ford oil play and improve well expected ultimate recovery (EUR) and economics.

The goal of geothermal reservoir management is to economically recover as much energy as possible from the reservoir. This paper presents the development of improved techniques for monitoring and predicting two-phase mass and heat transport in fractures. Partitioning tracers can yield valuable, early information about fracture properties used within a semi-analytical approach for calculating enthalpy production from the fractured system. This is demonstrated for a synthetic model with a fracture network. The comparisons of the semi-analytical solutions with the simulation results show that the model predicts enthalpy production is easy, fast and ideally suited for sensitivity studies.

When a shale gas reservoir is being developed, two fundamental questions need to be answered: (1) how much gas is in place and (2) how much gas can be produced when reservoir is depleted to a specific pressure. This paper examines the pore size distribution impact on gas volume in place during reservoir depletion. A calculation procedure for a multiple component system will be presented with an illustration using Barnett core mercury injection data. Literature suggests that a monolayer adsorption model is not sufficient for shale gas reservoirs with multiple components in volumetric calculations. In this paper, we propose to use the cylindrical Simplified Local Density model with Peng-Robinson Equation of State (SLD-PR EOS) to solve the local hydrocarbon density distribution for gas in micro-and meso-pores. The integration of the local density over the pore width yields an average density. Pore size distribution (PSD) data such as mercury injection provide the pore volume contribution of different pore radii. Coupling the pore volume distribution with the calculated average density, we calculate the gas in place due to pressurization and adsorption under different pressures. The recovery from the shale reservoir is determined by repeating the process at different pressures. Because of the high non-linearity of the SLD-PR EOS, a trust-region optimization algorithm has been used to solve the local density profile. Pore size distribution has a tremendous impact on the gas storage capacity of a shale formation. Results from this study reveal that neglecting PSD can yield more than 40% errors for original gas in place (OGIP) calculation. Incremental pore volume is modeled with a Log-Gamma distribution for the Barnett field. OGIP sensitivities to the distribution parameters are also investigated. For the same porosity under the same ambient pressure and temperature, more small pores indicate more gas in place. Therfore under the same depletion process, more recovery can be expected from small pores. This paper utilizes MICP data for a Barnett gas shale core sample to demonstrate the calculation procedure for implementing core data, fluid characterization, and SLD -PR EOS modeling to calculate original gas in place. This paper has the following two novel points: (1) An improved OGIP calculation procedure for multicomponent gas shales is proposed using the cylindrical form of the SLD-PR EOS model and MICP data from core samples; (2) PSD has a tremendous influence on OGIP values in shale formations because of the presence of micropores and neglecting PSD can yield significant errors in OGIP values.

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.

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.

Artificial lift design for heavy oil systems is a continual changing process in which evolving technological advancements coupled with constant learning experience has led to production capabilities that were not feasible in the past. There has been an increase in installation of temperature tolerant Electric Submersible pumps (ESP) with the primary aim of improving deliverability from mature heavy oil fields. Similarly, in the heavy oil industry, the desire to attain energy efficiency has birthed variations of the Steam Assisted Gravity Drainage (SAGD) process that use solvent additives in further reducing bitumen viscosity. The heavy oil emulsion formed in these systems exhibit rheological characteristics and outflow behaviors different to conventional SAGD systems. Tubing hydraulic performance, steam trap requirements and flow assurance behaviors associated with production from these systems are investigated in this work. This paper presents dynamic multiphase simulations detailing fluid flow regimes, mass and heat transfer mechanisms and pressure/temperature changes as the reservoir fluid flows out of the reservoir, through an ESP and up the production tubing to the surface. The reservoir is a 3D fully coupled reservoir/wellbore model with properties similar to the Athabasca bitumen reservoir. The simulation was conducted considering all periods in the lifecycle of production i.e. pre and post ramp up. This research finds that a detailed understanding of fluid phase behavior and reservoir operating parameters during the different periods can dramatically improve operating efficiency and impact on ESP design. Furthermore, results generated from this research can be used as a yardstick for SAGD production engineers in designing artificial lift systems for solvent assisted processes

In the United States, hydrocarbon in unconventional resources such as shale gas has been dramatically changing the fossil energy prospect and transforming the energy consumption structure. Therefore, it is imperative to study how this trend has impacted the U.S. natural gas import, export and the domestic gas price. To understand the relationships, Neural Network would be used to model these variables (gas production, price, import and export) with the ultimate goal of understanding the gas price determination. The key input parameters for the Network are gas production, import and export data and the resulting output of the Network would be the gas price i.e. how well this inputs influence gas price and there magnitude of impact would be ranked in this study. Impact of Weather would be looked into as well but it is not part of the Network inputs. Data from Energy Information Administration (EIA) of the U.S. Department of Energy will be utilized in this study. This work is motivated by the recent surging interest in converting existing gas import terminals to exporting terminals due to increase in gas production as a result of major technological advancement in getting formerly untapped gas out of the ground. The changes in the gas industry trend have prompted the government to consider policy changes as well. Our study will enable us to draw some policy implications regarding the U.S. energy policy.

Literature shows that there is a significant amount of natural gas available for enhanced recovery in the depleted reservoirs; at the same time, the depleted gas reservoirs are a proven storage facility for Carbon Dioxide (CO2) storage in terms of reservoir integrity. Conceptually, injecting CO2 into a depleted gas reservoir will not only potentially rejuvenalize the gas production, but will also store the greenhouse gas in a proven subsurface formation. Study on CO2 phase behavior in subsurface conditions shows that CO2 most likely will be in super-critical state which exhibits liquid-like density and gas-like viscosity. These properties are favorable in displacing natural gas reservoirs in volumetric and pore scale sweep efficiency. Using numerical reservoir simulation on a synthetic case with multiple scenarios, this paper identifies the most amenable characteristics of a reservoir for enhancing gas production by injecting CO2 and analyzes the parameters influencing this secondary recovery process. In the paper, reservoir depth, depletion pressure ratio, aquifer activity, inclination angle, reservoir heterogeneity with various permeability arrangement, injection rate, and producer bottomhole pressure will be studied on the synthetic model. Furthermore, this paper will quantify the amount of natural gas which can be produced and CO2 that can be stored in an ideal case using economic matrix. From this study, the ideal candidates for enhanced gas recovery by CO2 injection will be proposed based on simulation results, thus one can screen the available gas reservoirs for CO2 storage purpose and can quickly quantify the additional gas production from the secondary recovery.

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.

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.

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 accuracy and precision of well rates are paramount in reservoir management, well performance surveillance, flow assurance, and any third party processing arrangements. Rate allocation is traditionally based on well rate tests and downtime. This method is usually time-consuming and thus performed relatively infrequently. This could be inadequate for proactive asset management especially with wells that may produce in transient state. This paper discusses methodology to improve well rate allocation quality and save engineering time. In practice, many fields face some or all of the following challenges that are related to well rate allocation: 1) reservoir communication, 2) well interference, 3) changing skin factors or other near wellbore boundaries, 4) uncertainties around reservoir fluid properties, and 5) difficulty in obtaining well rate tests for a variety of reasons. For many intelligent wells, it is a common practice to install permanent downhole gauges which are playing critical roles in field management. This paper describes a framework on how to capitalize on the real time data from well pressure and temperature sensors and use the data in Integrated Asset Modeling (IAM) to allocate the well rate with enhanced accuracy, increased frequency, and reduced processing time. The paper uses Atlantis in Gulf of Mexico as an example to demonstrate this process. The real-time data supported model based allocation process becomes virtual flow meters for the intelligent wells. For Atlantis, field-wide allocation accuracy has been improved from previously +/− 10% error using the traditional allocation method based on well rate test and downtime method to current +/−3% error using the new method. This paper also shows model maintenance is a journey that needs strenuous attention especially after water injections commences and more production wells come online.