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Since the proof-of-concept field testing at AOSTRA's Underground Test Facility (UTF) in late 1980's, the SAGD (Steam-Assisted Gravity Drainage) process has been applied for many bitumen recovery projects in Alberta. According to public-domain data, these projects have shown a wide range of recovery performance - ranging from very good to very poor - on basis of actual Oil Rate & Volume, Steam-Oil Ratio (SOR) versus expected and/or nameplate design. SAGD recovery performance in these projects is mainly affected by geological deposits, reservoir quality and operational experience. Numerical modeling has been an important tool in SAGD commercialization development, including being used for production forecasting, evaluation of process operations and enhancements.
This paper first reviews and analyzes actual field production and injection data for 28 Athabasca Oil Sands Deposit SAGD well pairs (WPs). These WPs are from 4 different pads, in close proximity to one another, producing from reservoir of different qualities from Jackfish 1 SAGD project; they have more than 1700 days of history (from first steam to end of July 2013). It is seen that reservoir quality has a considerable (bigger than commonly believed) impact on recovery performance, particularly in terms of thermal efficiency (as measured by SOR) and steam chamber dynamics. Discussion is provided in view of observed field performance vis-à-vis current/common industry practice of field production forecasting and project development planning.
Another important finding from the production data analysis is revealed in the reported gas production behavior, including cumulative volume and trend. It is seen that in many of these 28 WPs, there was considerable ‘extra’ gas (commonly attributed to aquathermolysis) production - up to 20% of total gas produced at the end of approximately 6 years of steam injection. The analysis helps providing some answers to oft-asked questions from field operators about too much production of (sour) gas; it should also help future studies model more closely SAGD gas production, in addition to liquids production.
Based on the analysis of field production data, a numerical model was built and calibrated against production data from 2 of the poorer-performing WPs among the 28 studied. Agreement between simulated and actual Cumulative Oil and SOR was within 10%, after 6 years of operations, on a first-iteration basis. The model was also successful in modeling the gas production behavior.
Real-time analysis and data analytics have become cornerstones in reservoir management of waterflood operations or conformance program. Connectivity between injector-producer pairs and premature breakthrough of injected water or gas are perennial issues that can make or break the economics of secondary and tertiary recovery projects. In this study, we aim to harness the advances in modern data analytics and real-time analysis to systematically evaluate a suite of standard diagnostics tools and propose novel ones for improved recovery projects. Although the scope of these reservoir dynamics evaluation tools can be extensive, our current investigation utilizes data from the Permian Basin.
A suite of reservoir models under varying conditions involving water injection helped understand and evaluate a number of diagnostics tools and devise new characteristics plots. We performed over 8,000 model runs and used data analytics to assess these tools. These tools include water/oil ratio (WOR) vs. time plot, Chan diagnostics, reciprocal-productivity index (RPI) plot, gas/oil ratio (GOR) vs. time plot, among others. We investigated the well-spacing effect ranging from 20 to 320 acres, grid effects, and heterogeneity effects in evaluating these tools. We also explored heterogeneity measures, such as the Dykstra-Parsons method and an index based on final hydrocarbon pore-volume injection (HCPVI), and ultimate recovery. Both cluster analysis and
This study shows critical parameters for oil recovery under waterflooding are reservoir flow paths and connectivity between layers, reservoir storativity, fluid properties, the thickness of the oil/water transition zone, and fluid mobilities. We also observed that the water breakthrough time does not show a clear relationship with IRPI. Nonetheless, the HCPVI at breakthrough time exhibited a linear correlation with the ultimate oil recovery. In the absence of water production or the presence of water channeling a linear trend emerges for the final HCPVI plot. Cluster analysis and real-time production data analysis have demonstrated the strength of a new reservoir dynamics indicator plot of ultimate hydrocarbon recovery vs. initial reciprocal productivity index. Combination of this indicator and traditional diagnostics and heterogeneity index can quantify the spread of final recovery efficiently.
Oklahoma has been at the center stage of induced seismicity. Water-disposal activities have been attributed to trigger the increasing number of seismic events. The objective of the study is to provide a simple diagnostics method and procedure for safe water-disposal operations. A comprehensive suite of scenarios and parameters has been analyzed that affect water disposal. Prognosis based on this study will lead to safe water-disposal operation without the adverse effect.
A suite of reservoir models involving water injection helped understand disposal-well performance. The well operational limits correspond to disposal-zone fracture gradient. The modified-Hall analysis is employed to ascertain the point of departure from normal injection behavior. Limiting cumulative injected volumes are determined and investigated for various scenarios from simple to increasingly complex subsurface conditions. This investigation includes studying the effects of disposal-zone storativity, compartment size, conductivity, formation compressibility, heterogeneity, and natural fractures. Additionally, we explored the effects of communication with overlying producing zone, communication through completion anomaly, seal integrity and fluid complexities.
This study illuminates an overall understanding of disposal-well performance through various scenario analyses. A relationship of disposal zone fracture gradient and limiting cumulative injection volume is established. For a fracture gradient of 0.7 psi/ft, this limiting pore-volume injection is less than 2%, which corresponds well with the conventional wisdom learned from CO2 injection-well performance. The relationship of disposal-zone compartment size, established with rate-transient analysis, with limiting cumulative injection volume is formulated. Analyses from the various statistical design of experiments reveal the important variables that may affect disposal-well performance. The disposal-well operation can be devised in real time using the modified-Hall analysis that can reveal the departure from normal injection-well behavior. Factors accentuating the departure from normal behavior include disposal-zone storativity, formation compressibility, and seal integrity. Situations, where pressure release through leaks or communication with an adjacent formation takes place, will naturally accommodate a larger volume of disposal water. Also, we learned that limiting cumulative injection volume and not injection rate (assuming injection pressure gradient is less than the fracture gradient) triggers a departure from normal injection behavior.
Using a suite of numerical reservoir models and the reservoir-monitoring tools involving modified-Hall and rate-transient analyses led to a comprehensive understanding of disposal-well performance. This study found a relationship of fracture gradient with limiting cumulative injection volume and identified key variables affecting the disposal-well behavior. These findings led to a smart and safe disposal-well monitoring scheme, which will help disposal-well management become more economic and environmentally friendly.
The purpose of this paper is to introduce a stochastic seismic inversion algorithm based on Markov Chain Monte Carlo Simulation. The suggested inversion scheme generates a set of possible combinations of rock properties that can explain seismic amplitude responses in terms of lithology, pore structure and fluid variations. The result of the probabilistic seismic inversion is a seismic lithofacies catalog than can describe the elastic response of the studied subsurface interval. The main advantage of this technique is that the results consist of multiple equally probable rock properties models as an alternative to multiple elastic properties scenarios. Therefore, no post facto elastic to rock properties conversion is needed. The method might be used either in exploratory areas or hydrocarbon field development. In exploratory areas, the stochastic rock physics inversion can support the evaluation for hydrocarbon potential considering the effects of reservoir properties on seismic signatures for different geologic scenarios and physical conditions, with the prime goal of minimizing uncertainties and risk. In field development areas, stochastic seismic inversion produces multiple equally probable rock properties models that can explain the real 3D seismic response and can be used to constrain possible reservoir models used for hydrocarbon reserve estimation and reservoir production simulation. The probabilistic inversion algorithm was tested on a synthetic model that is based on real well log data. The objective of the synthetic test is to demonstrate the feasibility of the estimation of critical rock properties for hydrocarbon exploration, such as total porosity and reservoir fraction. The synthetic test results confirmed the capability of the proposed inversion technique to accurately predict the rock properties of the reservoir seismic lithofacies, even for seismically thin layers.
Conventional seismic reservoir characterization (SRC) techniques were developed more than forty years ago for exploration plays where the hydrocarbon’s seismic responses were relatively easy to identify. Early reservoir characterization workflows were usualy based on direct hydrocarbon indicator (DHI) identification techniques centered on post stack seismic amplitude analysis and AVO inversion. DHIs plays are usually related to shallow high porosity reservoirs with significantly lower acoustic impedance than the surrounding rocks. The associated seismic signatures of these hydrocarbon filled high porosity reservoirs can be anomalous high amplitude reflections called “bright spots”. Nowadays, conventional seismic reservoir characterization techniques are becoming obsolete, since the oil industry is moving to explore areas were the hydrocarbons are located in deeper and more complex reservoirs. These new hydrocarbon plays are characterized by low porosity and low permeability reservoirs with near to undetectable pore fluid response. It means that the future seismic reservoir caracterization goal is to predict rock properties such as porosity, lithology and rock fabric of compacted and cemented porous rock. The second more important SRC challenge is to improve the seismic vertical resolution. Currently, seismic inversion resolution is still low for the new exploration/development challenges and improvement of seismic derived elastic parameters is paramount for the application of reservoir properties prediction. Techniques such as stochastic inversion have been initially developed in an attempt to obtain from seismic data quantitative information about subsurface rock properties on a very detailed scale. The goal of this paper is to introduce an inversion technique based on Markov Chain Monte Carlo simulation that can be implemented in a stochastic petrophysical inversion scheme. The stochastic seismic inversion’s objective is to produce a set of equiprobable rock properties volumes that can describe the elastic seismic response of the studied interval and their associated uncertainties. The main advantage of this petrophysical inversion technique is that the results are multiple equally probable rock properties models instead of multiple elastic properties scenarios. Therefore, no elastic to rock properties conversion is needed after the inversion is performed. The method might be used either in exploratory or development areas.
In shale formations, natural gas flows either through nano-scale pores or fractures during production period. Darcy’s law cannot effectively describe such transport phenomena due to its continuum assumption. Alternatively, kinetic-based lattice Boltzmann method (LBM) becomes a strong candidate of simulating organic-rich shale reservoir that contains a large amount of nano-scale pores. Among various LBM models, multiple-Relaxation-Time (generalized) LBM is considered as one of the most efficient models regarding its theories, selections of parameters, and numerical stability. For gas flow in a confined system, its molecular mean free path depends on not only the size of the confined system, but also the distance of gas molecules from solid walls. A large amount of natural gas is believed to be stored in extremely small organic pores, and adsorption in shale has a significant influence for gas transport in production. In this paper, we incorporated adsorption into generalized LBM model in order to capture the natural gas flow in organic nano-pores. Many factors are believed to control the flow mechanism in such pores, such as the size of organic pores, specific surface area, adsorptive strength, and so on. Generalized LBM results shows a great agreement with available data for high Knudsen flows between two-dimensional parallel plates. Accounted the effect of adsorption, flow phenomena are investigated by varying different controlling factors in both simple and complex structures.
Shale gas has been becoming a significant source of unconventional natural gas. The production of shale gas mainly depends on its characteristics, such as the pore distribution, organic richness, natural/factitious fractures, etc. A significant portion of shale gas is stored in kerogen pores that are ranging 2nm to 50 nm [1, 2, 3]. Consequently, it is essential to understand natural gas flow in nanopores to be able to predict long-term shale gas production as well as shale gas reserves.
Funes, Alejandro (Tecpetrol S.A.) | Figini, Fernando (Tecpetrol S.A.) | De Franceschi, Esteban (Tenaris) | Actis Goretta, Emiliano (Tenaris) | Castineiras, Tomas (Tenaris) | Wang, Xiuli (Xgas) | Economides, Michael J. (U. of Houston)
Although invariably well tubulars have been connected with a thread compoundto prevent corrosion and the galling of the metal itself, innovativetechnologies have allowed the introduction of dope-free connectivity byengineering the connections at the end of pipe sections. Avoiding the useof dope compounds has apparent benefits, one of which is the prevention offormation damage. Another is the efficiency and reliability of the operationitself, removing a cumbersome, albeit routine job, a major advantage in thehectic time of a drilling rig's operation.
During the connection assembly a portion of the thread compound is exudedoutside the connection and gets access to the well fluids through the tubingand annular space. Laboratory studies by us with core experiments, presented inthis paper, show that the dope forms a suspension which penetrates and damagesthe formation. The damage is severe (more than 99 percent) and will be presentin any well injection service. For production the issue is different and willdepend on the reservoir permeability and the ability or lack thereof of thedope compound to penetrate the rock matrix or whether it will form a removablefilter cake.
The reason that this problem has not gained widespread notice is perhapsbecause the problem has a narrow application of formation permeability, onethat we delineate in this work. Additionally, we present evidence that the dopecan be washed off usually by simple flow of reservoir fluids and/or brines orit can be partially dissolved by simple solvent treatments employing toluene orxylene.
We present here the clear benefits of using dope-free pipe connections byquantifying the negative effects of the alternative. Production equations usinga dope-induced skin effect are presented, showing the detrimental impact onwell performance.
Marine compressed natural gas (CNG) has been considered in the past as a meansof natural gas transportation but proved to be a non-starter for a number ofreasons including long distances or large volumes of gas when compared withliquefied natural gas (LNG). However, marine CNG still figures economicallyattractive over shorter voyages (up to ~4,000km) and medium volumes of gas.Recent advances in containment systems are poised to provide marine CNG withthe best opportunity to be resurrected as a major enabler of new and previouslystranded hydrocarbons by becoming an important optimization tool to petroleumwell performance.
Almost half of offshore natural gas, SEC-type, reserves are considered"stranded" because of the high unit technical cost to harness natural gas inremote locations involving deep-water and/or pre-salt basins, and the lack of areliable and commercially viable market for the natural gas. Most of them donot contain enough gas to justify their own gas transmission solution, floatingor onshore LNG production. Furthermore, inoperable gas affects oil productionin many adverse ways from the logistics of handling and facilities capacity tothe cost of the treatment. Marine CNG used as a wellhead fluid shuttlingservice for raw gas can generate significant monetary benefits for an operatorattributable directly to the new technology and innovative application. Gasviewed like this is no longer a mid-stream product in need of furtherprocessing prior to sale, but becomes a potential upstream saleableproduct.
We present here the new technology emphasizing the containment systemmanufactured with composite materials that are far lighter than metal and yetcan withstand the 200-atmosphere pressure and corrosion from hostile raw gascomposition straight out of the primary separator. CNG cargo containment systemproduced with composite materials can reduce overall steel weight by 50-80% andcan operate with pressures ranging from 150 to 250 bars, sufficient toaccommodate a wide range of gas-oil-ratios without the need ofrefrigeration.
Hydraulic fracturing treatment has been proven to be one of the key technologies for shale gas development. Micro-seismic mapping data has shown that hydraulic fracturing stimulation has often resulted in complex fracture network due to the geological complexity of shale formations. Hydraulic fracturing is a coupled process of shale formation deformation and flow of engineered fluid that includes water, proppant and other chemicals. Moreover, the pre-existing natural fractures in shale formation may complicate hydraulic fracture propagation process and alter its Young's modulus.
In this paper, we have developed a numerical model for modeling hydraulic fracture propagation in highly fractured shale formation. The proposed numerical model has integrated turbulent flow, rock stress response, interactions of hydraulic fracture propagation with natural fractures, and influence of natural fractures on formation Young's modulus. Mixed finite element method is employed for numerical solution of the nonlinear partial differential equations. The proposed model has been validated with bi-wing hydraulic fracture model through regression tests. The preliminary numerical results illustrate the significant differences in modeling hydraulic fracture propagation in comparison with current models that assume laminar flow in hydraulic fracture process. Two simulated cases with different initial natural fracture mapping are given. The preliminary numerical results show that length and density of natural fracture have significant impact on formation Young's modulus, and interactions between hydraulic fracture and natural fractures create the complex fracture network.
This model provides an opportunity to optimize hydraulic fracturing stimulation design through numerical simulations, which is vital in shale reservoir development.
Hydraulic fracturing stimulation is one of the key technologies in shale gas development and has often, as shown in micro seismic mapping, resulted in complex fracture network geometry due to the interaction between hydraulic fracture and pre-existing natural fractures (Fisher et al. 2002; Maxwell et al. 2002; Daniels et al. 2007; Le Calvez et al. 2007; X. Wang et al. 2011). Though it has been widely used in oil and gas industry for many years, it remains a great challenge to quantitatively characterize the hydraulically induced fracture network in shale gas development due to the complexity of the network and lack of the observational data.
Hydraulic fracturing is a stimulation process, in which engineered fluids, a mixture of water, sand and chemicals, are pumped into shale formation at high pressure and rate to create an induced fracture network. In the stimulation process, high flow rate and fluid pressure initiate and propagate the hydraulically induced fracture. The induced fracture can open the natural fracture or cross it, or can be rested by the natural fracture once it intersects with a natural fracture (Blanton, 1982; Warpinski, N.R, 1987; Renshaw, C.E., 1995, and N. Potluri, 2005). Consequently, it is critical to model the coupling effects of the flow process and the fracture propagation.
Underground natural gas storage has been used extensively in countries withlarge natural gas demand. Although much of the storage and withdrawal have beenassociated with seasonality, storage is becoming essential in an integratednatural gas management. It is particularly important in large operations, suchas liquefied natural gas (LNG), where the total production rate must bemaintained irrespective of the producing field day-to-day capacity.
Natural gas storage capacity is affected by reservoir volume and tolerablepressure (to avoid fracturing) and injection or production rates that areaffected by reservoir permeability, natural reservoir drive mechanism, wellcompletion/stimulation, and the impact of cyclical losses.
We present here a new sequence of calculations and estimations demonstratingsalient elements of this practice:
• Maximum capacity estimation with a new type of graphical construction, blendingconcepts of the classical p/Z vs. cumulative recovery straight line in naturalgas production.
• Prediction of withdrawal rates and time, constrained by decreasing storagepressure.
• Determination of maximum or sustainable withdrawal rate for a period of time.In all cases, the injecting and producing wells are hydraulically fractured.The hydraulic fractures are designed for the withdrawal rate. Thus, therequired number of wells is determined.
These concepts are applied to a depleted natural gas field with an averagepay of 33 ft and a permeability of 45 md. Forecasts of injection or productionrates, cumulative storage or withdrawal, and pressure buildup or decline arepresented as functions of time. The purpose of this case study is to sustain anLNG liquefaction operation for a specified period of time by employingunderground natural gas storage.
Thread compound "dope?? in the vernacular, has been used routinely in assembling joints of casing and tubing. The practice in almost universal application in the oil and gas industry involves the manual application of the lubricant in a fashion that is rudimentary, non-systematic and unquantifiable. There is evidence presented in this paper that damage to the near-well zone and other unpleasant events may be associated with the thread compound.
This paper presents the results of both laboratory and field investigations quantifying the effects of the dope on near-well damage. During the assembly of tubing and casing a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations.
To characterize and quantify the problem, core samples from the El Tordillo field, with different permeabilities were used. The samples were subjected to the circulation of the suspension created by the thread compound and the completion fluid, measuring the change in the core permeability. The work simulated the well conditions during water injection for water injection wells and during acid treatments for producer wells. A significant reduction in permeability, manifested by a fast and a very large increase in pressure, was measured, at the front face of the core sample. The same measurements showed a far smaller impact in the core body suggesting very minor penetration of dope particles.
This paper describes the laboratory and field work, with description of the test protocols, well conditions and laboratory emulation of field conditions that were used.