bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Measurements and Correlation of K-value, Viscosity, and Density Data for Mixtures of Light to Heavy Solvents and Athabasca Bitumen with Applications of ES-SAGD Process
Authors: Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal
Published: May 2016

Alberta's oil sands reserve is one of the largest known hydrocarbon deposits. Current commercial recovery methods are steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). These methods need a large amount of steam per unit volume of oil produced. This results in both high energy consumption and enormous impact on environment due to water treatment and greenhouse gas emissions. Expanding-Solvent SAGD (ES-SAGD) has been suggested to overcome the problems associated with these processes by associating solvent with steam injection. ES-SAGD not only reduces the environmental impacts but also increases the bitumen production efficiency. Therefore, ES-SAGD results in higher oil recovery with less production costs and reduced environmental impacts. The key pre-requisites for simulation and design of ES-SAGD process are the phase behaviour data consisting k-value, density, and viscosity of solvent-bitumen mixtures at high temperatures up to 250 °C and moderate pressures up to 6 MPa.

In this study, experimental k-value data of carbon dioxide and different hydrocarbon solvents in bitumen as well as experimental measurements of density and viscosity of solvent-bitumen mixtures are presented. Carbon dioxide and hydrocarbon solvents of methane to pentane are covered. The most of ES-SAGD projects are operated at temperatures close to 250 °C while the available experimental data in literature covers the temperature conditions up to 180 °C. Accurate correlations with solid thermodynamic background are presented to estimate the data at high temperature regions required for simulation of ES-SAGD process. These correlations are evaluated with the new measured experimental data.

The results showed significant difference between behaviour of light and heavy solvents in low and high temperature regions. At low temperature conditions, viscosity reduction of light solvents is more pronounced than heavy solvents while at high temperature regions heavy solvents are more effective. Comparison between the experimental data at high temperatures (240 °C) and the modelling results showed that the proposed correlations can be applied where the experimental data at high temperatures are not available. The experimental data and correlations in this study can be used for simulation and optimization of ES-SAGD processes in Alberta bitumen reservoirs.
Steam Circulation Strategies for SAGD Wells After Geomechanical Dilation Start-Up
Authors: Zhang Jing , Fan Yuxing , Xu Bin , Yang Baohong , Yuan Yanguang , Yu Yangfei
Published: May 2016

Dilation start-up has been widely used in Petro-China's Xinjiang oil field as a means of reducing start-up time and enhancing production from its "super" heavy oil reservoirs through the Steam-Assisted Gravity Drainage (SAGD) process. SAGD dilation start-up employs geomechanical dilation mechanisms to achieve these preferred results. Using a short-period of small-volume and high-pressure fluid injection, the dilation start-up facilitates the development of a dilated zone that vertically connects the SAGD well pair and is laterally uniform along the length of the well. This zone allows for more effective heat transfer to the inter-well area through convection than what is achieved through simple conduction during the conventional SAGD steam circulation start-up. In Petro-China's Xinjiang oil field, conventional SAGD start-up requires 10 to 12 months of non-productive steam circulation before oil production can begin. Wells treated with the SAGD dilation start-up can be converted to production after only 2 to 3 months of steam circulation.

This paper presents optimized steam circulation strategies which can be used with the dilation start-up treated SAGD well pairs. Numerical simulations are effectively integrated with field trials to derive best practices for steam circulation after the dilation start-up. The objectives are to get earlier and increased SAGD production as well as enhanced horizontal steam conformance. Operating parameters such as steam injection pressure, rate and pressure difference between the SAGD well pair were found to influence these objectives.
Predicting SAGD ESP Intake Temperature
Authors: Fedenczuk Leon , Graham John , Pehlke Trent , Cherniwchan Nicholas
Published: May 2016

This paper introduces a formula for predicting the intake temperatures of an ESP during SAGD operations, the "Lagged PVT Ratio Formula". This formula is intended to be used to automate the ESP's operation, with the goal of maintaining select well temperature and subcool targets. Target intake temperatures are determined and are currently monitored manually. If downhole temperatures reach a critical, typically water saturation temperatures, vapors can form at or in the ESP. This can cause the pump to trip or fail, leading to a costly workover being required.

To develop the Lagged PVT Ratio Formula data from eight well pads, approximately 80 SAGD well-pairs, was used. It is based on lagged non-dimensional ratios derived from select well parameters known to effect ESP intake temperatures. Formula inputs are based on the previous five readings of select variables in 10 minute intervals. Frequent readings of appropriate parameters allow for fast and accurate temperature predictions during sensitive well operating periods, and periods of stable production. Accurate temperature predictions are specifically important during the initial start-up period of the well. Verification tests showed that a single equation can be used to predict the ESP's intake temperature for SAGD well-pairs at different stages of the wells life. This formula has proven to be consistently robust and does not change when applied to similar existing well-pairs, well-pairs with different geology, and new well-pairs.

With an increasing number of producing SAGD well-pairs on site, being able to predict ESP temperatures, leading to well-pair automation, will be an economical benefit for operators. It will allow for additional SAGD well-pairs to be drilled without requiring additional production engineers to monitor and operate the wells on a daily basis.
Understanding Impacts of Lean Zones on Thermal Recovery in View of Mobile Water
Authors: Xu Jinze , Pan Yi , Chen Zhangxin
Published: May 2016

Lean zones have been reported in Nexen's Long Lake project and Suncor's Firebag project in Canada. With high steam-oil ratio and low oil recovery caused by lean zones, developing a heterogeneous oil sand reservoir is a considerable challenge. To study the mechanism of how lean zones affect thermal recovery performance, the role of the huge volume of mobile water cannot be neglected. In this paper, we propose a new mass transfer model for the thermal recovery process in oil sands with mobile water. Further discussions based on the model showed the following conclusions: (1) Reservoir regions during thermal recovery are divided into four regions based on initial water saturation. An increase in the initial water saturation may cause the oil bank to disappear. (2) The initial mobile water saturation significantly reduces the width of the two-phase flow region once it is larger than the frontal water saturation of this region. (3) High water saturation leads to a long breakthrough time in a hot driving region and low oil recovery. (4) Large connate water saturation and porosity and small heated oil viscosity benefit the oil recovery before the breakthrough of the steam chamber.
A Proxy Model for Predicting SAGD Production from Reservoirs Containing Shale Barriers
Authors: Zheng Jingwen , Leung Juliana Y. , Sawatzky Ronald P. , Alvarez Jose M.
Published: May 2016

An approach based on artificial intelligence (AI) tools is being used to explore the influence of shale heterogeneities on SAGD production. In this project, the production data is derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs.

The underlying reservoir simulation model is homogeneous, and two-dimensional. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. Superimposed on this homogeneous reservoir model are sets of idealized shale barrier configurations. The permeability of each shale barrier is several orders of magnitude smaller than the permeability of the oil sand in the simulation model. The individual shale barriers are categorized by their location relative to the SAGD well pair (vertical and lateral), and by their geometry (thickness and lateral extent).

SAGD production was simulated with the reservoir model for a training set of shale barrier configurations. The training set was chosen to try to span the space of possible shale barrier configurations in the reservoir model; the elements of the set were identified by means of experimental design. A network model based on AI tools was constructed to match the output of the reservoir simulation model for this training set of shale barrier configurations, with a focus on the production rate and the steam-oil ratio (SOR). Then the trained AI proxy model was used to predict SAGD production profiles for scenarios where the shale barriers were distributed stochastically. The results of these predictions were compared with the results of the SAGD simulation model with the same shale barrier configurations. The match to production rate and SOR was good, better than expected.

The results of this work demonstrate the capability and flexibility of the AI-based network model, and of the parameterization technique for representing the characteristics of the shale barriers, in capturing the effects of complex heterogeneities on SAGD production. The approach could be extended to study the effects of other heterogeneous features such as lean zones on SAGD production. It offers the significant potential of providing an indirect method for inferring the presence and distribution of heterogeneous reservoir features from the profiles of SAGD field production data.
In-Situ Combustion Experience in Heavy Oil Carbonate
Authors: Ismail Norasyikin B. , Klock Kristina A. , Hascakir Berna
Published: May 2016

In-situ Combustion (ISC) has the potential to be the most effective enhanced oil recovery (EOR) method for heavy oil recovery. However, it is considered a high risk failure rate process since it is hard to predict the combustion reactions between complex crude oil and heterogeneous rock matrices. If the reservoir rock is reactive, like carbonates, the risk factor of ISC increases. This research studies the ISC performance for different rock matrices found in Alberta, Canada.

The reaction kinetics analyses were carried out by Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) on bulk oil, and its Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions at a constant heating rate (20°C/min). To better understand the combustion behavior of bulk oil, pseudo blends of SARA fractions were prepared and systematic TGA/DSC tests were run on these blends. Furthermore, the impact of reactive porous media on fuel formation mechanism was investigated by using clays and carbonates. The reaction kinetic analyses on bulk oil and SARA fractions suggest that asphaltenes, resins, and aromatics fractions go into endothermic reactions at elevated temperatures, still the asphaltenes fraction generates the greatest amount of heat. The two-component interaction of asphaltenes with other fractions produces less heat than the combustion of asphaltenes alone. The three- component pseudo blend prepared by mixing asphaltenes-resins-aromatics produced the highest amount of heat and we believe that in bulk oil combustion saturates by acting as an ignitor provides the necessary heat to initiate the reactions among aromatics, resins, and asphaltenes fractions. Moreover, the effect of reactive porous media on reaction kinetics of bulk oil were investigated at a constant heating rate (20°C/min). Carbonates and clays were used. Since the clays act like a catalyst, heat generation was observed lower with clays than carbonates and carbonates required more heat for successful combustion.

While the heating rates during in-situ combustion are generated naturally, in TGA/DSC tests, a constant heating rate is applied. In this study, we used 20°C/min as the heating rate. If the same heating rate during ISC cannot be reached, then, the heat generation cannot be as high as reported in this manuscript. Thus, it is important to extend the systematic TGA/DSC analyses presented in this paper. Tests should be conducted at varying heating rates on different oil samples and on their SARA fractions.
Produced Gas Reinjection Based Cyclic Solvent Processes for Foamy Oil Reservoirs in the Eastern Orinoco Belt, Venezuela
Authors: Li Xingmin , Yin Yin , Yang Zhaopeng , Shen Yang , Liu Zhangcong
Published: May 2016

Solution gas drive from heavy oil reservoirs in the eastern Orinoco Belt, Venezuela presents foamy oil behavior and has shown a primary recovery factor of 8-12%. However, the cold production performance will get worse continuously during such a pressure depletion process, and steam injection sometimes is not an economically attractive follow-up candidate for improving the oil recovery further especially at the low oil price condition. Therefore, produced gas re-injection based processes in huff and puff mode, i.e., hydrocarbon-based cyclic solvent processes (CSP and ECSP) have been tested to evaluate their applicability to such reservoirs.

In this study, the oil sample used in the test is taken from Block M, Eastern Orinoco Belt. The viscosity and the API gravity of the stock tank oil of Block M are 14,488cp (at 54 °C) and 7.8 respectively. The produced reservoir gas is mainly a mixture of methane and CO2 (87:13 in molar ratio). Firstly, the heavy oil swelling test and unconventional PVT test are conducted. And then the behavior of primary depletion process and produced gas huff and puff (CSP) is investigated by conducting a series of sandpack tests. In addition, to further improve the performance of the produced gas CSP, three different enhanced cyclic solvent processes (ECSP), including produced gas and propane, produced gas and foaming agent, and produced gas plus oil viscosity reducer ECSP are tested.

The 3-cycle produced gas CSP test result shows that it can improve the oil recovery by 8.7% compared to primary depletion when the first CSP cycle is initiated at a certain pressure between the bubble point pressure and the pseudo bubble point pressure. The CSP process illustrates obvious restoration of the foamy oil drive mechanism which provides primary production, or so called secondary foamy oil drive mechanism. Above three different ECSP processes all improve the CSP performance with different degrees. The produced gas and propane ECSP (70% produced gas +30% propane), with produced gas slug injected before propane slug during each injection process, improves the oil recovery by 23.6% through three cycles compared to cold production due to viscosity reduction and solvent-gas-drive mechanisms. For 3-cycle produced gas and foaming agent ECSP, and produced gas plus oil viscosity reducer ECSP, the increased oil recovery are 15.5% and 11.2% separately.
Compositional Mechanisms in SAGD and ES-SAGD With Consideration of Water Solubility in Oil
Authors: Venkatramani Arun Venkat , Okuno Ryosuke
Published: May 2016

Experimental data have shown that the solubility of water in the oleic (L) phase (xwL) can be significant at elevated temperatures. However, xwL was not properly considered in prior studies of SAGD and ES-SAGD. The main objective of this research is to present a detailed study of compositional mechanisms in SAGD and ES-SAGD simulation by considering xwL. The importance of properly considering xwL is shown in economic evaluation of these bitumen-recovery processes.

The phase-behavior models used in this research are carefully created on the basis of experimental studies presented in the literature. Mechanistic simulation studies are then conducted for SAGD and ES-SAGD. Co-injectants used in ES-SAGD simulations range from propane through n-decane.

Results show that xwL enhances bitumen production in both SAGD and ES-SAGD mainly because xwL results in reduction of L-phase viscosity. The enhancement is more significant when the chamber-edge temperature is higher, because xwL increases with temperature. The enhancement of bitumen production observed in the case studies is 7.66% for SAGD, 4.08% for C6-SAGD, and 4.85% for C8-SAGD for a fixed period of operation at 35 bars. It is important to consider xwL in SAGD and ES-SAGD simulations, because the relative performance of ES-SAGD to SAGD tends to be overestimated without considering xwL.

On the basis of a sensitivity analysis for economic performance of ES-SAGD, a guideline is presented to leverage xwL to improve bitumen production in ES-SAGD. As discussed in our prior research, solvent becomes effective in diluting bitumen and reducing steam requirement, only when it sufficiently accumulates near the chamber edge. New results show that water can act as a diluting agent until solvent sufficiently accumulates near the chamber edge.
Steam-Air Injection Process
Authors: Chang Jeannine , Ivory John
Published: May 2016

This paper summarizes the results of reservoir simulations performed to investigate steam-air injection and its potential as a thermal recovery process. The steam-air injection process is considered to be any process that involves both steam and air injection whether they are injected together or at different times. The objective of the simulations was to develop steam-air injection based on its ability to divert steam from more to less oil depleted regions thereby improving reservoir contact (conformance) and increasing oil production. This diversion is caused by the deposition of coke and/or asphaltene in depleted regions or high permeability channels or thief zones. It primarily results from low temperature oxidation (LTO) of the oil. Air injection is most effective when used to divert injected steam when significant channeling/over-riding is occurring prior to air injection.

Air should be injected at a relatively low rate and temperature in order that coke/asphaltene deposition occurs and facilitates steam diversion. Simulations showed that in a field application of the steam-air injection process, it is important to stop injecting air with/without steam once diversion has been obtained. Otherwise, oil will unnecessarily be consumed or degraded by LTO reactions and steam diversion may be reduced due to consumption of deposited coke/asphaltenes by high temperature oxidation (HTO) reactions. Continued injection of air could even increase channeling as it removes the coke and any residual oil by oxidation reactions thereby reducing the flow resistance in channels/thief zones. Air injection in a steam process is complex and it is not simply a case of injecting air with steam without careful consideration of the process.
In-Situ Reflux: An Improved In-Situ Recovery Method for Oil Sands
Authors: Harding Thomas G. , Zanon Stefan , Imran Muhammad , Kerr Richard K.
Published: May 2016

The steam-assisted gravity drainage (SAGD) process is the only commercially proven in-situ recovery method for Athabasca oil sands but it is challenged by high capital and operating costs and project economics are very sensitive to oil price fluctuations. The SAGD process also uses large quantities of water and produces significant greenhouse gas emissions during steam generation. It has become important to develop lower cost and more environmentally sustainable in-situ recovery technology for Athabasca oil sands.

In-situ reflux (ISR) is a new and lower cost alternative to SAGD that uses long electrical resistance heaters in horizontal wells to vaporize connate water to produce a rising steam chamber above the heater well. In ISR a relatively small amount of water or solvent may be injected to enhance heat transfer into the formation and assist in reducing bitumen viscosity. Steam condensate formed by the cooling of steam migrates downward along with heated bitumen but as these fluids approach the heater well and production conduit, the water is re-vaporized or refluxed while the oil continues its downward travel and is produced. SAGD-like horizontal well pairs are contemplated for ISR although it may be possible to operate single wells. Capital costs for ISR are much reduced compared to SAGD since there are no steam generators, only a small water treatment plant is needed and the required capacity of the production separation train is significantly reduced. Operating costs for ISR are also reduced compared to SAGD through elimination of surface and wellbore heat losses during energy transmission to the producing formation. Greater energy efficiency in ISR leads to lower carbon dioxide production and water requirements compared to SAGD. This paper presents a description of the ISR process, a comparison of the SAGD and ISR processes and the steps taken to assess the viability of ISR. The many possible applications of the ISR recovery process are also discussed.
An Experimental Investigation of the Effect of pH and Salinity on Sand Control Performance for Heavy Oil Thermal Production
Authors: Mahmoudi Mahdi , Fattahpour Vahidoddin , Nouri Alireza , Leitch Michael
Published: May 2016

In this paper, we present the results of an experimental investigation on the effect of pH and salinity on slotted liner performance in terms of sanding and retained permeability for heavy oil thermal production. This work is an advancement of the existing knowledge in the literature which indicates that pH and salinity could highly affect the mobilization, flocculation and deflocculating of clays (mainly Illite and Kaolinite) in oil sands formations.

Water with different pH, in the range of 6.8 to 8.8, and salinities, in the range of 0 to 1.4 % was injected into sand pack samples supported with multi-slot coupon in a Sand Retention Testing (SRT) facility. Measurements included pressure drops along the sand pack and across the slotted liner coupon as well as the produced sand/fines for different flow rates. These measurements were used to assess the effect of the pH and salinity on fines migration within the sand pack, capability of the slotted liner to produce the fines, pore and slot plugging, sand production and the retained permeability.

We observed that the pressure drops, fines production and the retained permeability are highly dependent on the pH and salinity of the injected fluid. In low pH and high salinity environment, clay is not mobilized resulting in low pressure drops and high retained permeabilities. On the other hand, an increase in pH value or a decrease in salinity leads to significant clay mobilization and a remarkable reduction in retained permeability.

This paper provides a thorough experimental investigation of the pH and salinity effect on slotted liner performance. The effect of the pH and salinity is usually ignored in screen control testing while it could highly control the clay mobilization and retained permeability. Results of this study could trigger wide reconsideration in sand control approaches particularly by altering the pH in the near wellbore zone.
Optimum Time of ACP Injection for Heavy Oil Recovery
Authors: Aitkulov Almas , Lu Jun , Pope Gary , Mohanty Kishore K.
Published: May 2016

Alkaline-cosolvent-polymer (ACP) flooding of a heavy acidic oil (320 cp) was studied in a two-dimensional (2D) sand pack. An ACP formulation was developed by studying the phase behavior of the oil with several alkaline-cosolvent formulations. The effectiveness of the ACP formulation was validated in a 1D sand pack by conducting a waterflood followed by a stable ACP flood. Sand was then packed into a 2D square steel cell equivalent to a quarter five-spot pattern. Several ACP floods were then conducted in this 2D cell to study both the displacement and sweep efficiency of ACP floods. First, the polymer concentration in the ACP formulation was varied to find an optimum ACP slug viscosity where the oil recovery and pressure gradients are acceptable. When the ACP slug viscosity was about 1/4 of the oil viscosity, oil recovery was 76% OOIP; we adopted this viscosity as the optimum viscosity. Then, using this ACP slug viscosity, the waterflood extent, after which the ACP flood was initiated, was varied (0-1 pore volume). The oil recovery, oil cut, effluent concentration and pressure drop were monitored during the floods. The timing of the tertiary flood did not change the tertiary oil recovery very much. However, shorter the waterflood, faster was the oil recovery under the constant injection rate constraint. Sweep efficiency during secondary ACP flood was lower than that in the tertiary ACP injection. Gravity effect on sweep was significant under ultralow IFT.
Unconventional Production Forecast Needs Integration of Field Hydraulic Stimulation Data Through Fracture Model Calibration and Optimized Numerical Scheme
Authors: Delorme M.. , Bossie-Codreanu D.. , Ben-Gharbia I.. , Khebzegga O.. , Khebzegga N.. , Ricois O. M.
Published: May 2016

Objectives/Scope

Hydraulic fracturing is today a standard when developing unconventional reservoir plays. This is studied through different models, based on a great deal of characterization data gathering and analysis. Unfortunately, numerical limitations impose drastic simplifications (number of fractures, some data being ignored…) leading to simple fracture geometries, lacking observed complexity. This limits any design optimization expectation. Our objective is to show that calibration data used for simpler models, along microseismic measurements, can lead to more realistic hydraulic fracturing geometries. Results can be linked to a reservoir platform, forecasting production. The presented computationally efficient method, within which sensitivity is performed, highlights key parameters governing the stimulation process. This study shows that the tool used is tailored for practical scenario design and evaluation.

Methods, Procedures, Process

The method used to generate realistic fracture geometries implies information at all scales (seismic, log, cores…) as well as numerical tools able to handle geomechanics and fluid flow, over a great number of fractures (as required by the characterization). Thus all data is input into one 3D Representative Deformable Discrete Fracture Network (DDFN), simulating the hydraulic stimulation. Characterization is based on geostatistical concepts applied to both natural and hydraulically induced fractures, driven by geological and geomechanical data. The process is simulated using a one phase hydrodynamic model within the DDFN (specific discretization) under far stress conditions. Fractures behavior is governed by geomechanical laws, reversible and non-reversible, with an approximate proppant model. Various scenarios are tested according to either geomechanical uncertain parameters, or characterization ones. Observed in-situ Bottom Hole Pressure (BHP) and microseismic characteristics (shape, frequency…) are then history-matched.

Results, Observations, Conclusions

For each simulated scenario, quality of the history match is shown and discussed, stressing the representativity of the data involved.

The method has shown to be computationally efficient and robust enough to support hundred thousands of fractures while at the same time being able to simulate simpler cases. Also, within the studied framework, ties with already existing reservoir platform are shown. Advantages of such an approach are highlighted including current limitations of classical reservoir models.

Novel/Additive Information

This work undergone at different scales demonstrate the new possibilities of computational robust algorithms, within an approach considering both geological settings and geomechanical properties. The model offers the possibility to integrate several scales to an adaptive discretization scheme.
Lessons Learned in Permian Gas-Lift Shale Wells: Dynamic Production Analysis With Downhole Gauge
Authors: Gonzalez L. E. , Chokshi R. N. , Gonzales R. O. , Adams T..
Published: May 2016

Unconventional shale wells involve dynamic flow environments, which can be challenging to artificial lift systems required to produce these wells. Early-stage production from these wells is characterized by rapid production declines. Additionally, these wells experience significant production rate and phase fluctuations. Gas lift is a method of choice for producing gas-dominant assets, and it is commonly used early in the life cycle of liquid-dominant assets when production rates are higher. The design, the operation, and the general production management for shale wells requires a completely different approach and mindset than for conventional wells.

Production systems analysis, usually referred to as nodal analysis3, is a design and optimization technique used to evaluate a variety of current and future production scenarios under the assumption of steady state. Well test data, downhole gradient surveys, or production logging surveys are periodically sampled and provided as boundary conditions for the production systems analysis. The future reservoir conditions, typically obtained from reservoir simulations, are also used as boundary conditions. After performing the systems analysis, operators validate outcomes and determine the correct actions to take by using sporadic measurements. Operators are recognizing that the lower measurement frequency and resulting slower and offline analysis techniques provide incomplete, if not inaccurate, snapshots of the dynamic production environments of shale assets. To address that situation, several operators have started deploying downhole pressure/temperature gauges to understand and manage dynamic production behavior. There is a need for dynamic production modeling tools that analyze field conditions with realtime data and that provide real-time suggestions for corrective production improvement. This paper presents a dynamic production analysis methodology using real-time downhole measurements and its implementation in a software tool.

The presentation provides results from two shale wells produced using gas-lift technology in a Permian asset. Both wells are instrumented with permanent electronic downhole gauges below the operating orifice valve to measure pressure and temperature in the casing-tubing annulus and in the tubing. The real-time data from gauges is visualized and analyzed in real time to diagnose artificial lift performance, including gas-lift valve behavior. More importantly, the analysis-inferred reservoir static pressure and instantaneous productivity index can be compared to the numerical reservoir simulations.

Real-time downhole data coupled to dynamic production analysis is presented for the first time. This approach leads to more accurate production forecasting as well as optimization of highly dynamic shale wells.
Brittleness Analysis: A Methodology to Identify Sweet Spots in Shale Gas Reservoirs
Authors: Rojas L. Fernandez , Peña Y. Quintero , Carrillo Z. H.
Published: May 2016

The purpose of this paper is to propose a methodology based on analyze the impact of the brittleness index in hydraulic fracturing on shale gas reservoirs worldwide, and thereby define parameters to identify fraccable feasible sweet spots in shale plays prospects.

A literature review was made so as to gather the largest amount of mechanical, petrophysical and geochemical data from shale gas reservoirs from countries all over the world such as United States, China, Argentina, Holland, Norway, Denmark and Sweden. Once available the data, different methods were used to calculate the brittleness index of each study case considering the effect of the mineralogical composition and elastic moduli such as Young's modulus and Poisson's ratio, both static and dynamic.

The relation between the brittleness index at depth and the total organic carbon allowed to identify possible sweet spots within each prospect reservoir. Additionally, the analysis of brittleness index and mechanical behavior of those reservoirs permitted to establish what kind of fracturing fluid should be used in case of a hydraulic fracturing at those sweet spots, in order to achieve the most effective stimulation process.

Integrated analysis of mechanical, petrophysical and geochemical properties is a practical methodology that allows to identify shale gas prospects by establishing analogies with known productive shale reservoirs, especially in countries where unconventional resources potential have not been estimated yet.
Gas Lift-Jet Pump Hybrid Completion Reduces Nonproductive Time During Unconventional Well Production
Authors: Pino O. A. , Pugh T. S. , Hubbard J..
Published: May 2016

Gas lift is a preferred lifting method to produce unconventional wells across the world. During specific stages of the well life, however, it might happen that water percentage raises enough to make the tubing flow gradient too high for lifting with the maximum operating pressure and rate of injection gas. This results in unplanned nonproductive time. A slickline-deployable jet pump can be a cost-effective alternative to effectively unload the well and resume production with gas lift.

The addition of a sliding sleeve door (SSD) to the tubing string, installed between the deepest gas lift mandrel and the annular packer, will allow the deployment of a slickline-set jet pump. The backup jet pump provides a valuable and cost-effective alternative in three potential scenarios: when unloading fracking fluids before beginning gas-lift production, when restoring production after an unpredicted shutdown of the gas-lift compression system, and when the producing water cut becomes higher than expected.

An operator in Logan County, Oklahoma, installed the gas lift-jet pump hybrid completion in five wells. The completion was basically designed for gas lift with a standard "X" profile SSD installed between the packer and the operating gas-lift valve. The dual-purpose tubing string was installed in each well in one trip. To produce fracking fluids left in the wellbore, standard-flow jet pumps were set in the SSD, mobile hydraulic-lift surface units were hooked up to the Christmas tree and jet pump production operation started. On average, fracking water was produced 66% faster than by swabbing and rod pumping, and 33% faster than with nitrogen lift. Upon recovery of the fracking fluids, the wells were producing enough gas to successfully start the gas lift systems in approximately 6 days.

This simple but ingenious dual-purpose completion approach has already proved to solve the problem of unconventional well production load-up during the early production stage of gas lifted systems. The information provided in this paper will help operators plan, design, deploy, and operate a dual-purpose gas lift-jet pump well completion.
Comprehensive Determination of the Far-Field Earth Stresses for Rocks With Anisotropy in Tectonic Environment
Authors: Frydman M.. , Pacheco F.. , Pastor J.. , Canesin F. C. , Caniggia J.. , Davey H..
Published: May 2016

Geomechanics has become an important tool for engineers and geologists, with classical applications in wellbore stability, sand management, and hydraulic fracturing. However, unconventional shale reservoirs cannot be evaluated with traditional models or on the basis of simple relationships between isotropic elastic properties, far-field stresses, and reservoir and mechanical properties. These plays are geologically complex and the reservoirs are heterogeneous in nature. Wells need to be hydraulically fractured for stimulation and, in a complex tectonic environment, the rock fabric and in situ stress strongly influence this process. We discuss a new methodology developed for stress modeling, taking into account the tectonic environment. We present a case study for the Vaca Muerta formation in Argentina. The obtained results contribute to the understanding of stress distribution in unconventional reservoirs.
Pressure Transient Analysis of Complex Fracture Networks in Shale Gas Reservoirs With Multiple-Porosity Transport Mechanisms
Authors: Teng W.. , Jiang Y.. , Jiang R.. , He J.. , Gao X.. , Liu Z..
Published: May 2016

Shale gas flow is controlled by multiple mechanisms and multi-stage hydraulic fracturing often creates complex fracture networks. It is very challenging to incorporate various migration mechanisms of shale gas and accurately simulate the complex fracture networks in shale gas reservoirs. In this work, we present a semi-analytical model to study the pressure behavior in shale gas reservoirs. Multiple migration mechanisms are considered, which contain diffusion of dissolved gas in kerogen bulk, desorption from the surface of kerogen bulk and clay particles, slippage flow simultaneously from both organic pores and inorganic pores into natural fracture system and Darcy flow in natural fractures and hydraulic fracture network system. Line source function, Laplace transformation and the principle of superposition are employed to analytically describe flow behavior in reservoir system and a numerical discrete method is adopted to simulate the complex fracture networks. Main fractures and secondary fractures within the fracture networks are divided into elements with equal length. Gauss elimination method and Stehfest inversion algorithm are employed to calculate the pressure responses. We perform three case studies which contain multistage transverse fracture, orthogonal fracture network and un-orthogonal fracture network. Type curves are plotted and possible flow regimes are identified. With its rapid computational speed, yet capturing the physics of shale gas flow, this semi-analytical approach provides an efficient tool for people from multiple disciplines to perform pressure transient analysis of complex fracture networks in shale gas reservoirs.
Optimization of Enhanced Coalbed Methane Recovery With C02 Injection
Authors: Temizel C.. , Betancourt D. J. , Tiwari A.. , Zhang M.. , Aktas S. S. , Quiros F..
Published: May 2016

Objectives/Scope

Coalbed methane (CBM) has become an important source of clean energy in the recent decades worldwide including the US, China, Australia, India and Russia with more than 60 countries having different degrees of promising coal reserves. CBM reservoirs are distinguished from conventional reservoirs due to the major difference in the mechanism of gas storage and production of water. In CBM reservoirs, pores act as the major storage mechanism as gas is trapped and stored there and produced by means of dewatering and thus lowering the reservoir pressure. Free gas forms as the pressure is lowered leading to increased gas permeability of coal and thus increasing recovery. Microbial activity and thermal maturation of organic compounds are the main mechanisms of methane generation in lower-and-higher rank coals, respectively. Even though methane is an abundant and clean energy source, there are certain operational, technical and economic challenges involved in its production due its unique nature outlined above. Thus, a strong understanding of the parameters and uncertainties that influence the recovery is crucial.

Methods, Procedures, Process

Due to the fact that the organic materials that make up coals generally have a stronger affinity for CO2 than for methane, CO2 is used as an enhanced recovery method to displace methane as an enhanced coalbed methane recovery (ECBM) method. While there is no current comprehensive optimization study on the effects of such factors, ECBM has a very significant role in the future of energy as it means more energy out of natural gas while eliminating the adverse effects of greenhouse gases.

Results, Observations, Conclusions

In this study, a standard SPE reservoir simulation model is used to study the factors influencing the recovery in coal bed methane reservoirs by investigating the significance of parameters including but not limited to porosity, adsorption capacity, fracture permeability along with coal density and irreducible water saturation.

Novel/Additive Information

The optimization results obtained by means of coupling a full-physics commercial numerical reservoir simulator with an optimization/uncertainty tool are presented outlining the different degrees of significance of these factors on production and ultimate recovery for better understanding of the phenomenon that will lead to more robust reservoir management decisions.
Comparison of Numerical vs Analytical Models for EUR Calculation and Optimization in Unconventional Reservoirs
Authors: Moinfar A.. , Erdle J. C. , Patel K..
Published: May 2016

Analytical models available in Rate-Transient-Analysis (RTA) packages are widely used as tools for history matching and forecasting production in unconventional resources. There has also been an increasing interest in the use of numerical simulation of unconventional reservoirs. In this study, we use both methods to history match the production of hydraulically fractured unconventional wells, followed by forecasting future production to establish a well's EUR (Estimated Ultimate Recovery) for reserves determination purposes. This study's goal is to quantify the differences one might expect to encounter in a well's EUR when using analytical model-based RTA vs numerical simulation-based workflows in unconventional reservoirs.

First, we consider an undersaturated shale oil reservoir as a base model for this study. The base case also satisfies all assumptions inherent to analytical solution-based methods such as homogenous reservoir properties and fully-penetrating planar fractures. An excellent match between results of both methods for the base model validates the numerical simulation approach. We then impose a series of real-world deviations from RTA assumptions and investigate reliability of EUR predictions made by both approaches. In all cases, historical data and reference EURs are derived from finely-gridded numerical simulations.

Example results show that, in the presence of real-world deviations from RTA assumptions, analytical models can still match the historical production data; however, key reservoir and fracture parameters need to be modified drastically to compensate for the lack of sufficient physics in the analytical models. Results show that the analytical solution-based history-matched models are not predictive for future production, and somewhat surprisingly provide pessimistic EURs in all real-world scenarios investigated in this work. For the cases presented in this study, analytical models under-predict EURs by 6-17% when two years of production history is available for matching. The underestimation of EUR increases drastically (up to 60%) as the length of available historical data decreases from 2 years to 3 months.

For all cases, we also apply an efficient numerical simulation-based workflow for probabilistic forecasting of EURs. This workflow provides multiple history-matched models that are constrained by historical production data. The probabilistic forecast method employed in this work provides P90 (conservative), P50 (most likely), and P10 (optimistic) values for EUR. In all examples, the range of P90 to P10 EUR values includes the reference EUR, and the P50 values are within 2.2% of the reference EUR.
Optimized Completions Design With Integrated LWD and Well Site Geochemistry for Petrophysical Analysis and Enhanced Well Placement
Authors: Crosby Z. S. , Mejia C.. , Langford C.. , Nardi G.. , Heard S. T. , Mainali P.. , Galindo J..
Published: May 2016

During the evolution of developing unconventional resources, large variability in production has pushed the industry to look at combining key petrophysical factors to gain insight into the production contributions of each stage in a completion design. Along the wellbore, petrophysical variabilities are minimized while the completions operation and design are optimized by placing the well in the target zone with minimal wellbore tortuosity.

Landing point identification and horizontal well placement using inorganic and organic elemental data acquired from drill cuttings and advanced mud-gas analysis at the wellsite, combined with LWD gamma ray spectroscopy enhances well placement decisions by providing a comprehensive near real-time chemostratigraphic interpretation. This is achieved while also maximizing petrophysical integration efficiency for well completion designs.
An Effluent Stream Treatment and Analysis System to Counteract Water Availability & Usage Issues for Unconventional Oil & Gas Resources
Authors: Alkhawaja A. A. , Hashem M. H. , Fernandes M. O. , Raheem N. O.
Published: May 2016

As production from unconventional (shale) oil and gas rises, large volumes of water are produced as a by-product. These water streams contain a variety of contaminants including: Total Dissolved Solids (TDS), Total Suspended Solids (TSS), Naturally Occurring Radioactive Material (NORM), heavy metals. Treating this water incurs additional costs. Moreover, abiding by environmental regulations set by authorities is the responsibility of the operator. In addition, hydraulic fracturing (fracking) operations consume a lot of water.

This paper proposes the use of an online monitoring system to evaluate the water quality, which can be linked to a downstream program to evaluate the profitability of treating this water further. The Water Economic Feasibility Indicator (WEFI) program was also developed to help operators make decisions on the adequate water treatment technologies to employ based on economic parameters.

A case study is presented to evaluate the program, which involved using water production data from a field. The results showed that introducing Multi-Effect Distillation (MED) and Vapor Compression Distillation (VCD) technologies to treat the water further yields favorable outcomes. Graphs were plotted, demonstrating the associated costs of MED and VCD. Moreover, the cumulative net present value (NPV) of profit generated from sales of potable water is higher for VCD than MED.

Another possible use of this water is agriculture and livestock watering. This lowers the water stress in the region. Findings indicate that it is profitable to process the water to a potable/irrigation level using VCD equipment than to dispose of it, thereby providing net monetary, social, and environmental benefits.
Two-Phase Flow Model and Well Testing Analysis for Multi-Stage Fractured Horizontal Well in Shale Gas Reservoirs
Authors: Xie W.. , Yang H.. , Wu J.. , Feng X.. , Zhang X.. , Zheng M..
Published: May 2016

Two-phase flow in shale gas reservoirs is caused by water flowback after multi-stage fractured, this paper presents a two-phase pressure transient analysis model of multi-stage fractured horizontal well in shale gas reservoirs. With the new mathematics model, the two-phase flow characteristics and well testing analysis for early production period can be described.

The two-phase flow model is established by material balance law, Langmuir isotherm law and Fick diffusion law. Accurate solution to this flow model is obtained by source function theory, Laplace transform, three-dimensional eigenvalue method and orthogonal transformation. According to the solution, bilogarithmic type curve of the two-phase flow model is illustrated, the pressure transient performance under the effects of hydraulic fractures and shale gas reservoir properties are discussed.

It is found that there are seven different flow regimes which have been identified on the type curve of two-phase flow model, initial gas-water saturation, storage ratio and fractured stages have deeply impacted the type curve; absorption index, skin factor and interporosity flow coefficient have lower influence to the curve shape. According to the research results and field data of Lower Paleozoic shale in China, improved well testing analysis and dynamic monitoring have been provided. The research of this paper can make optimization design for the parameters selection of drilling and hydrofracture in shale gas reservoir.