bluuebunny/crossref_metadata_2025 huggingface dataset:
Borehole Flow Monitoring using a Non-intrusive Passive Distributed Acoustic Sensing (DAS)
Authors: Finfer D. C. , Mahue V. , Shatalin S. V. , Parker T. R. , Farhadiroushan M.
Published: October 2014

Historically in-well flow measurement has been challenged by downhole power requirements and post-installation inflexibility. Distributed acoustic sensing makes it possible to monitor the acoustic field along the entire length of a standard fiber optic cable, and therefore facilitate flow monitoring without any downhole electric power requirements. Further, the distributed nature of such systems enables post-installation adaptability as the production profile evolves. Partly as a result of this flexibility, distributed acoustic sensors have now started to gain momentum as a recognized solution for in-well flow surveillance.

In this paper, Silixa will present recent development work showing how distributed technology can enable high accuracy flow monitoring. Emerging results will be used to show how array processing of flow noise can be used to develop production data. Examples from the laboratory will be used to demonstrate these advanced techniques. It will be seen that advanced signal processing can be combined with knowledge concerning the physics of fluid-acoustic interactions to make determinations concerning the flow within a well. Finally, it will be shown that there exists strong promise for this upstream technology in a broad variety of well-types.
Enhanced Vapour Extraction (VAPEX) of Heavy Oils through Foamy Oil Flow and Viscous Fingering
Authors: Jia Xinfeng , Gu Yongan
Published: October 2014

Solvent vapour extraction (VAPEX) has shown great potential to recover heavy oil reserves. However, the application of the VAPEX technique is limited by its low oil production rate, which is caused by the slow mass transfer and inefficient gravity drainage. Hence, increasing the heavy oil–solvent mixing process and introducing more production mechanisms are imperative to enhance the performance of VAPEX. This paper proposes a new process, namely enhanced VAPEX, in which the solvent-chamber pressure is dynamically operated rather than constantly maintained throughout the production process. During the enhanced VAPEX process, pressure in the solvent chamber is cyclically depleted to induced foamy oil flow, which not only adds oil production but also increases contact area. In addition, a high-pressure non-condensable gas is applied to induce fingering phenomenon, which enlarges the heavy oil–solvent contact area. The enhanced VAPEX process is experimentally evaluated in this study. It is found that gas fingers can penetrate deep into the oil zone. In addition, foamy oil flow not only increases oil production but also improves mass transfer. Experimental results show that the oil production rate of the conventional VAPEX process was increased by 182% by the enhanced VAPEX process.
The Value Added of Five Years SPE-PRMS
Authors: Kreft Eric , Godderij Raymond , Scheffers Berend
Published: October 2014

The SPE-PRMS reserves reporting system has been adopted by EBN since 2009. As of that date a new PRMS project database has been developed. It currently contains more than 1000 hydrocarbon projects in the prospective, contingent and reserves categories. The annual (176 million BOE) and historic production (7.5 billion mln BOE) of over 250 oil and gas fields is stored on a monthly basis.

Apart from annual reserves reporting, the database is used for tracking and estimating hydrocarbon project maturation in the Netherlands. Each project contains a production forecast, and a prognosis of its maturation from resource to reserves in production, inclusive probability of maturation (POM) and probability of success (POS). Project attributes give insight in historic and future development of hydrocarbon plays and themes, such as Dutch tight gas and offshore infill drilling potential.

The implementation of the PRMS has significantly contributed to the understanding of the hydrocarbon maturation process in the Netherlands. It has proven a valuable system for hydrocarbon maturation analysis and reporting. It provides insight in the current and future activities of the Dutch E&P Industry. It offers the opportunity to steer on a national level to optimize future hydrocarbon production. It is highly appreciated by both technical staff and managers. The value of applying PRMS with project attributes is demonstrated by various examples.
MPD Techniques Optimize HPHT Well Control
Authors: Elmore Robert J. , Medley George H. , Goodwin Robert C.
Published: October 2014

The subject High Pressure High Temperature (HPHT) well proved extremely challenging with reservoir BHT of 334°F and approximate 13, 900 psi reservoir pressure. Managed Pressure Drilling (MPD) was originally selected to avoid a classic "Kick-Loss-Kick" scenario while drilling deep Austin Chalk formation wells in East Texas. While a secondary goal of MPD ("to ascertain the downhole pressure environment limits") was accomplished, the greatest benefit of MPD was seen while handling several well control incidents that occurred in the HPHT reservoir section. Optimal control of these incidents was facilitated by modification to the MPD technique and reconfiguration of the BOPE to allow for more appropriate application of the MPD equipment.

During drilling, a combination of high temperature and fluid properties (drilling fluid and reservoir fluid) resulted in repeated failures of the annular preventer and at least one variable bore ram (VBR) element failure at low pressure relative to the equipment rating. Ultimate integration of BOPE and MPD equipment allowed drilling with MW at or near balance to reservoir pressure.

Following and during trips, allowance had to be made for mud property changes caused by heating or cooling effects at both the surface and downhole. The mud property changes affected Equivalent Circulating Density (ECD) while drilling and tripping. Mud monitoring proved critical.

As HPHT and drilling technology mature, the line between flow control and well control begins to blur. Rather than transitioning from one to the other and back, the drilling and well control activities tend to become parts of a single process. This process, as described in the paper, must take into account the effect of variations in drilling fluid properties. Knowledge of the exposure limitations to pressure, temperature and other parameters and the effects on composition of pressure sealing elements in all surface and downhole tools is critical. The operator must also account for the effect of HPHT on specialty equipment such as RCDs, extra choke manifolds or manifold elements, and additional monitors. Adjustments in utilization and acquisition of slow pump rate information, use of the entire active pit system while circulating out kicks, and handling uncertainties in the downhole pressure regime are also part of this process. How alternative casing design affects well control while circulating a kick (influx) and using other unconventional drilling techniques will also be described.
Extending Lateral Length Using Casing Floatation to Reduce Field Development Cost in Shale Gas Plays
Authors: Blake R.
Published: October 2014

Operating in a low margin gas environment, operators look for new ways to reduce costs and efficiently develop reserves. Shell Canada Limited ("Shell"), operating in the Montney shale gas field located in NE British Columbia, Canada, used casing floatation techniques to extend lateral lengths. Increasing lateral length reduces well cost per lateral meter. This is because drilling the reservoir section is the least expensive segment due to high penetration rates. Extended lateral lengths also create new options for more economical and sustainable field development as fewer wells are required to cover acreage and it reduces dead space.

Shell uses a mono-bore casing design with average lateral lengths of 1800m at a TVD of 2300m. The goal of the project was to double lateral length to 3600m. At these depths, extending much beyond the current design is not possible due to theoretical casing lock-up from excess drag during conventional casing running. Casing floatation was chosen to extend the lateral reach of the wells and mitigate casing lock up because it is a cost effective, simple technology. Casing rotation and setting a deep intermediate string to reduce drag were also evaluated but deemed too cost prohibitive or technically unfeasible.

This paper documents the process and successful results of Shell's undertaking in doubling lateral length using casing floatation technology on five test wells in the area. It also provides detailed evaluation of post-run data to calibrate casing running models and the future impact of these results on an economical field development.
Practices Maintain Straight Hole in Crooked Hole Conditions, While Also Enabling Significant Gains in Drill Rate
Authors: Knudsen Steven D. , Dupriest Fred , Zemach Ezra , Blankenship Douglas A.
Published: October 2014

Bottom hole assembly (BHA) designs were assessed in field trials for their ability to achieve critical low inclination requirements, while simultaneously enabling high drill rates. Because angle has historically been controlled by reducing weight on bit (WOB), these are often competing priorities. The use of real time surveillance of mechanical specific energy (MSE) provided unique insights into the bit dysfunction that occurs with many practices used to control angle. These quantitative insights supported the development of BHA and operating practices that maintained low angle while also achieving major gains in drilling performance.

The McGinness Hills field in Lander County Nevada is a geothermal operation with wells drilled in hard metamorphic and crystalline formations. Wellbore inclinations must be maintained below 2.0 degrees in the critical 20 inch interval in order to allow use of lineshaft pumps, which is challenging in the required hole sizes and rock hardness. Formation strengths are similar to petroleum operations in the Rockies and West Texas.

Pendulum and packed-hole assemblies were tested, and straight motors and slick assemblies were used for corrections. Well build rates were assumed to be controlled by the three-point curvature in the lower assembly and stabilizer placement was modified to control this curvature. The effectiveness of the curvature control as WOB was increased was evaluated from inclination measurements. Real time MSE analysis was used to manage bit operating performance and to determine the root causes of bit dysfunction.

The results demonstrated that packed-hole assemblies could be designed that controlled inclination while enabling 2-3 times higher WOB, and that the use of pendulum assemblies should be eliminated. Packed assemblies drilled 87% faster. The increased WOB resulted in higher drill rates, major reduction in whirl and extended bit life, which are equally important performance objectives in hard rock drilling. The use of MSE surveillance allowed the physical processes to be understood deterministically, so that the philosophical design principles can be applied in other petroleum and geothermal operations.
Developing an Innovative Nano-Coated, Smart Material to Optimize Efficiency of Oilfield Completion Applications
Authors: Carrejo N. , Espinoza O. R. , Wibowo H. , Gaudette S. L.
Published: October 2014

As the oil and gas industry moves to more unconventional completions and drilling of ultra-deep, high-pressure wells, emerging technologies will be required to increase reliability while maximizing performance and minimizing operational costs. The development of a high-strength disintegrating metallic (HSDM) is one such technology, as it incorporates high ultimate compressive strength (UCS) and an engineered disintegrating mechanism tailored per application. The high-strength rating of HSDM pushed the development of disintegrating gas lift valves (GLV) and frac balls capable holding 15 ksi frac pressures. The ability for the new composite metallic to disintegrate in common wellbore fluids provided flow assurance by eliminating production risks provided by common frac balls. These applications proved the reliability of the material with hundreds of GLVs and thousands of frac balls utilized in wells around the world. This smart material has since been incorporated into ball seats and high-impacting telescoping ports (HITP) to increase the efficiency of delivery systems in hydraulic fracturing or acid stimulation treatments. The disintegration mechanism of the HSDM allows the ball seat to completely dissolve, eliminating the need to run a mill-out operation to increase the flow area of the production string. The HSDM is highly compatible with oil-based mud systems allowing this smart material to be incorporated within drilling liners or extended-reach production strings while operating as a fluid loss barrier. This application enables the operator to ensure proper fluid placement, while having the option to displace to brine systems or acid to remove the HSDM barriers to provide formation access. This paper will outline the development of this innovative smart material and discuss the inclusion and functionality of HSDM within the described applications.
Microfluidic Platform for PVT Measurements
Authors: Molla Shahnawaz , Mostowfi Farshid
Published: October 2014

In this work, we present a small-scale pressure/volume/temperature (PVT) cell which allows for the measurement of saturation pressure and phase-volume ratio using only a few microliters of reservoir fluid sample. This novel PVT measurement technique has been successfully tested on a wide spectrum of live reservoir fluids at elevated pressure (86 MPa) and temperature (150°C).

In the microfluidic PVT platform, the small microfluidic device performs the same function as the laboratory-scale pressurized visual PVT system. At the heart of the microfluidic device is a long and narrow capillary, densely packed in a serpentine shape, embedded on the device. The capillary is nearly 1-m long and has a total volume of 5 μl. The microfluidic device is fabricated using glass and silicon which allows visual monitoring of a fluid sample at various pressures and temperatures. To acquire PVT data, the pressure in the capillary is systematically reduced to accurately detect the appearance of micron-size gas bubbles in a sample at saturation pressure. Due to the small thermal mass of the device, the temperature of the sample can be changed rapidly, which enables the measurement of multiple saturation pressures in quick succession. Below the saturation pressure, the growing gas bubbles form a segmented gas-liquid distribution in the capillary. The lengths of the liquid and gas segments are measured in real-time using an automated image capturing and analysis tool to determine the gas-liquid phase-volume ratio at a given pressure.

Validation tests have proven this technique to be repeatable and feasible for rapid PVT measurements of black oils. The results presented in this study demonstrate that the microfluidic PVT system performs at the same level as the conventional PVT with significantly smaller sample volume and faster turnaround. The microfluidic PVT system is demonstrated to have the potential to become a reliable and portable measurement platform.
The Subsurface and Wells Emergency Response Organisation (ERO) Portal
Authors: Cormack Sarah , Yuile Jeanette
Published: October 2014

A Subsurface and Wells Emergency Response Organization (ERO) Portal has been developed to provide European subsurface and wells emergency response duty team personnel with immediate access to a critical, trusted subsurface and wells data set. The rapid availability of such a data set is linked to the speed and efficiency of the overall wellsite emergency response procedure.

The ERO Portal is a web based application. It is a simple and easy to use one-stop-shop that provides the subsurface and wells emergency response duty teams with access to 21 critical, high quality data types at field, well and wellbore level. The data types have been selected to provide a holistic understanding of the status of the assets (wellbores, wells, fields or Assets (groups of fields)), thereby enabling a highly informed emergency response based on the conditions of the assets involved.

The ERO Portal not only provides access to the 21 critical data types but differs from conventional data retrieval portals in that it indicates the availability or absence of each data type – thus saving time in the data gathering process. The user friendly home page connects to quality checked, published corporate data held and managed within corporate data stores.

On and offline back-up systems have also been developed to ensure full data availability at all times and duty team personnel are trained in how to use the tool.

The sustainability of the ERO Portal involves continual input from a number of teams throughout the year to ensure that data is quality checked and published in a timely manner into the corporate databases, that duty team personnel are trained in its use and that the IT technology is working at all times. However, there is no question that the investment in this tool is essential.

The ERO Portal is significant in that it offers an example of how providing a critical, trusted and quality checked data set from a single source in the event of a wellsite emergency can prove a vital step in a timely and well informed response to a wellsite emergency.
Impact of Maturity on Kerogen Pore Wettability: A Modeling Study
Authors: Hu Yinan , Devegowda Deepak , Sigal Richard
Published: October 2014

Kerogen wettability is essential to evaluate hydrocarbon storage and quantify reserves estimates, to develop models for multiphase and multicomponent transport especially in oil shales and to predict recoveries of fracture water as well as predict the placement of fracture water during re-fracture treatments. The widely held view for kerogen pores is generally hydrocarbon-wetting; however, some recent experimental work indicates the existence of water content in kerogen. The kerogen maturation process is associated with the loss of H/C and O/C ratios which may influence the wettability depending on the affinity of these functionalized molecules with water. In this paper, we provide a microscopic study of the role of kerogen maturity on wettability of organic pore systems.

Varying maturation degree of kerogen surfaces are built by grafting functionalized groups onto the traditional graphene model. We study a mixture of water and alkanes in organic pores with effective width of 5 nm. We find that water aggregates to form clusters, and the shape and the location of the water molecules are strongly linked to the density of the functionalized groups. By determining the contact angles, we are able to quantify the relationship of kerogen wettability with the maturity level.

We demonstrate that the wettability in kerogen is very likely to be heterogeneous. Depending on the maturity level, kerogen may be hydrocarbon wetting at high maturity, neutral wetting at intermediate maturities or even hydrophilic for organic surfaces of very low maturities. In addition, we also demonstrate the influence of surface heterogeneity and the distribution of polar molecules on kerogen wettability. Our results indicate that in kerogen there may be a critical local density of surface functionalized sites that may create optimal conditions for hydrophilic kerogen surfaces.
The Case for Utilizing Hydraulic Jet Pumps in the Bakken
Authors: Clark Chris W. , Griffin Larry , Pearson C. Mark , Strickland Stacy
Published: October 2014

The Bakken boom in North Dakota has been well documented. From a development perspective, the majority of the acreage has been drilled with an initial well to hold the acreage and the emphasis has shifted to infill drilling. In the early development stages, the primary goal was to prove up and hold leases. Now with the shift to full development, optimization of drilling, completion and production operations is the primary goal.

To date there has been a fair amount of discussion industry-wide regarding drilling and completion techniques as these are critical to play and area assessment. Little attention, however, has been paid to production techniques that optimize well performance and specifically artificial lift selection. This is a critical next step in order to maximize the value of these Bakken assets.

The vast majority of wells in the Bakken utilize sucker rod pumps as the method of artificial lift. This is largely attributable to the institutional knowledge and simplicity of the system. However, given the depth of the Bakken and high produced water density, sucker rod systems are not practically able to move the large volumes of fluid many wells are capable of delivering. Also, these systems will not optimally handle the large variations in deliverability as these unconventional wells rapidly decline in their early life. For wells within the study area with similar completion types, well deliverability greatly exceeds the installed sucker rod pump lift capabilities for more than a year, with measured fluid levels of 3,000′ to 6,000′ above the pump intake. This not only restricts production but creates operational issues with salt and scale deposition due to the high mineral saturations in the produced water seen in the Bakken where produced waters can approach 11 ppg densities.

In order to take full advantage of the authors’ advanced completion strategy utilizing plug and perf, slickwater, and 100% ceramic proppant, hydraulic jet pumps were chosen to get the wells closer to a "pumped off" state and to more optimally lift the wells during the early high-decline period where the deliverability is greatly changing. Thirteen installations were performed while Liberty operated properties in the Central Basin of the Bakken play. This paper discusses the superior production results achieved with jet pumps compared to sucker rod installations utilizing constant type curve parameters while varying initial production to fit the curve to production data. It also discusses the learning curve of the installations and operational advantages noted while applying this method for artificial lift.
Measurement and Analysis of 3D Stress Shadowing Related to the Spacing of Hydraulic Fracturing in Unconventional Reservoirs
Authors: Dohmen T. , Zhang J. , Blangy J. P.
Published: October 2014

Industry experience in unconventional plays shows that production performance does not scale up in simple increments when adding hydraulic fracture stages in closely spaced completions. That is, adding stages to a planned well by reducing the stage spacing does not proportionally enable additional hydrocarbon production on a per stage basis. Instead, closer stage spacing incrementally adds less hydrocarbon production per stage. Determining the appropriate stage spacing is an optimization step that the industry has approached by drilling statistically significant numbers of wells to separate the effects of completions from the effects of geologic variations. We propose leveraging and integrating microseismic data with associated measurements to analyze and model the effects of reduced stage spacing while drilling fewer wells.

Hess Corporation is using downhole geophones to monitor microseismic events associated with hydraulic fracturing in horizontal wells with different completion stage spacings in the Middle Bakken Play and the Utica Play. By constructing a small 3D structural model around each well, we create depth histograms of microseismic events. The events are measured in relation to a common stratigraphic boundary in order to identify how hydraulic fractures interact. Stage to stage analysis of these histograms shows a systematic interference phenomenon, which we demonstrate by applying 2D Fast Fourier Transform, correlation, and quantile analysis to the histograms.

A comparison of three horizontal wells stimulated with different stage spacing and in different plays shows that hydraulic fractures in closely spaced stages interfere with each other by cyclically bouncing out-of-zone. We find from microseismic observation that the stress shadowing induced by closely spaced stages exhibits a 3D behavior. That is, when hydraulic fractures develop in-zone, as planned, stress accumulates and forces subsequent completions preferentially upward, out-of-zone. As stress accumulates in the zone above, the following fractures reform and are back in-zone in a repetitive cycle. We believe that the physics controlling incremental hydrocarbon production per stage is related to this observed cyclical reduction of the in-zone fracture area. We then analyze the changes to in-situ stress induced by closely-spaced hydraulic fracturing, using a simple model. The concept uses geomechanical principles to explain the in-zone and out-of-zone phenomenon observed in multi-stage fracturing. In the future, we plan to apply 3D stress shadowing theory to our completion models to optimize the stage spacing of our production wells.
A New HLD-NAC Based EOS Approach to Predict Surfactant-Oil-Brine Phase Behavior for Live Oil at Reservoir Pressure and Temperature
Authors: Ghosh S. , Johns R. T.
Published: October 2014

Surfactant-polymer (SP) floods have significant potential to recover waterflood residual oil in shallow oil reservoirs. A thorough understanding of surfactant-oil-brine phase behavior is critical to design SP processes. Current practices involve repetitive laboratory experiments of dead crude at atmospheric pressure in a salinity scan that aims at finding an "optimum formulation" of chemicals for targeted oil reservoirs. While considerable progress has been made in developing surfactants and polymers that increase the potential of a chemical enhanced oil recovery (EOR) project, very little progress has been to predict phase behavior as a function of formulation variables such as pressure, temperature, and oil equivalent alkane carbon number (EACN). The empirical Hand's plot is still used today to model the microemulsion phase behavior with little predictive capability as formulation variables change. Such models could lead to incorrect recovery predictions and improper SP flood designs.

In this paper, we develop a new predictive phase behavior model and introduce a new factor β to account for pressure changes in the hydrophilic-lipophilic difference (HLD) equation. This new HLD equation is coupled with the net-average curvature (NAC) model to predict phase volumes, solubilization ratios, and microemulsion phase transitions (Winsor II−, III, and II+). The predictions of key parameters are compared to experimental data and are within relative errors of 4% (average 2.35%) for measured optimum salinities and 17% (average 10.55%) for optimum solubilization ratios. This paper is the first to use a HLD-NAC model to predict microemulsion phase behavior for live crudes, including optimal solubilization ratio and the salinity width of the three-phase Winsor III region at different temperatures and pressures. Although the effect of pressure variations on microemulsion phase behavior are generally thought to be small compared to temperature induced changes, we show here that this is not necessarily the case. The predictive approach relies on tuning the model to limited experimental data (say at atmospheric pressure) similar to what is done for equation-of-state modeling of miscible gas floods. This new equation-of-state-like model could significantly aid the design of chemical floods where key variables change dynamically, and in screening of potential candidate reservoirs for chemical EOR.
Utilizing Microseismic Stress Release to Identify Out-of-Zone Fracture Growth
Authors: Preiksaitis Mike , Bowman Sheri , Urbancic Ted , Baig Adam
Published: October 2014

Out-of-zone fracture growth can lead to inefficient stimulations and the loss of energy and injection fluids to surrounding rock formations. In unconventional shale resource plays, complexity in fracturing and lithology has a profound affect on the success of a completion program. In this paper we discuss the characteristic changes in seismic response associated with two case studies. The first study consists of out-of-zone fracture growth in inter-bedded sequences of shaley sandstone and carbonates. A zipper frac completion program was used on two stacked lateral treatment wells. A consistent stimulation program was utilized over all stages, however, following a shutdown interval of two days, upon re-initiation of the stimulation program, events migrated out-of-zone into the surrounding carbonate layers. These events were characterized by higher stress release values, consistent with the idea that fracturing was taking place in the carbonates and that more energy was required to activate fractures than typically seen in the fracturing of the shales. This suggests that during the shutdown interval, a relaxation in local stress magnitudes resulted in the re-orientation of the principal stresses into more optimal orientations to allow for fracturing within the carbonates. In a second case study, the stimulation of the Muskwa, Otter Park and Evie formations in the Horn River Basin, in Northeast British Columbia, resulted in localized out-of-zone growth for stimulations in all formations. These events were characterized by large stress release values, in contrast to the observed values for surrounding events within each formation. The evidence of high stress release within the formations suggests the activation of a fault that extended well below the target formations. Based on these observations of stress release, we postulate how additional seismic characteristics, such as stress release, can be used to identify out-of-zone growth in real-time.
Mitigation of Terrain Induced Slugging Using Mixer Devices
Authors: Brasjen B. J. , Veltin J. , Hansen J. H.
Published: October 2014

The present work focuses on experimental evidence of slug mitigation via various devices. The slug mitigation potential of a number of mixers was tested using a laboratory scale air/water setup to compare their effect on the incoming slugs just upstream of the separator inlet. Dedicated methods and key performance indicators were developed to characterize the slug properties and evaluate the mixers effectiveness.

Such mitigation is especially interesting for the purpose of producing oil and gas from thin oil rims, in which wells are often drilled following the geological structure of the oil-bearing layer. These wells consequently contain many long, near-horizontal sections, through which the transport of the oil gas mixture often takes the form of slug flow, i.e. large volumes of liquid travelling at the velocity of the gas phase. As the gas cannot bypass the slugs, they are generally produced to the topside facilities, where they have a detrimental effect on the mechanical integrity of the equipment and on the metering accuracy due to their large volume. Mitigating slug flow has therefore great potential in optimizing the production from thin-oil rims on the short term.

The present study shows that consistent reductions can be obtained on pressure fluctuations due to slugging, highlighting the benefit of these devices. It was observed that the slug speed could be significantly reduced, as well as the liquid hold-up within the slugs, especially when gas lift is used in conjunction with the devices. The physical mechanisms behind these effects are isolated, leading to optimization of the device geometry, for application to full scale.

The demonstrated potential of the mixer devices can yield a quantifiable reduction of the impact of slugging on mechanical integrity and metering accuracy. As a consequence, production limitations due to slugging problems can be alleviated, resulting in potential for increase in oil production rates from thin oil rims.
How to Improve our Understanding of Gas and Oil Production Mechanisms in Liquid-rich Shale
Authors: Alfi Masoud , Yan Bicheng , Cao Yang , An Cheng , Wang Yuhe , Killough John
Published: October 2014

Three phase oil, gas, and water flow in liquid-rich shale plays is investigated in this paper, using a state-of-the-art technique of dividing shale matrix into different sub-media. Shale reservoirs always present numerous challenges to modeling and understanding, from unintuitive, heterogeneous, and difficult to characterize rock properties, to limited understanding of the governing flow equations, lack of fundamental knowledge on related desorption mechanisms, and nearly impermeable formations with pores on the order of magnitude as the mean free path of gas molecules. This work proposes a partitioning scheme to divide porous media in shale into three different sub-media (porosity systems) with distinctive characteristics: inorganic matter and kerogen (in the shale matrix), along with fracture network (natural or hydraulic). The current model gives us the capability of better analyzing the complex nature of mass transfer in shale. Relative permeabilities in our model are accounted for by employing the functions specifically presented for shale reservoirs. Our model can also handle various flow and storage mechanisms corresponding with shales such as molecule/wall interactions and slippage of the gas phase, multicomponent desorption, and capillarities. Simulation results show that hydrocarbon production from shale reservoirs exhibits complicated dynamics that are controlled by a number of different factors. Because of very high capillary pressure in shale, water is observed to imbibe into the water-wet inorganic matter during the late production period. On the contrary, mass flow in the oil-wet kerogen is mostly limited to two-phase oil and gas flow. Although kerogen is considered to be a rich source of hydrocarbon, relatively high capillary pressure and very low rock permeability hinder oil production in organic-rich shale. We might be able to address such problems by employing an appropriate production enhancement technique compatible with the ultra-tight nature of such reservoirs.
Numerical Model for Mapping Thief Zones in Directional Wells while Drilling
Authors: Chen Yuanhang , Yu Mengjiao , Ozbayoglu Evren , Takach Nicholas
Published: October 2014

Failure to minimize lost circulation can greatly increase the cost of drilling and the risk of well abandonment. The main reason why some of the remedial procedures are not working as planned is the lack of information in loss zone locations. Inaccurate estimation of loss zone location prevents the treatment to be applied directly at the point of loss, results in low efficiency and extended nonproductive rig time.

This paper describes an approach for identifying the location of loss zones in directional wells using distributed temperature measurement while drilling. A transient thermal model for predicting the temperature profile in a directional well with mud loss is presented. The numerical solution under different lost circulation conditions, when used together with the distributed temperature measurement, can identify the location of mud loss. For a deep high pressure high temperature well with severe lost circulation, there is a significant change in the thermal behavior of the wellbore as mud loss continues. The characteristics of wellbore thermal behavior are evaluated and identified as good indicators of loss zone location. The distributed temperature measurement while drilling is enabled by a drilling microchip technology that has been developed and validated with successful field tests. By matching simulated results with the distributed temperature measurements at different timestamp, the depth of the loss zone can be accurately identified. Case Studies are given to show the practical applications of the method. The results are important in applying expandable tubular system, setting cement plug and spotting lost circulation pills. An additional application of this approach is the identification of highly permeable zones for reservoir or formation evaluation.
Development of Innovative and Efficient Hydraulic Fracturing Numerical Simulation Model and Parametric Studies in Unconventional Naturally Fractured Reservoirs
Authors: Ahn Chong Hyun , Dilmore Robert , Wang John Yilin
Published: October 2014

The most effective method for stimulating unconventional reservoirs is using properly designed and successfully implemented hydraulic fracture treatments. The interaction between pre-existing natural fractures and the engineered propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical simulators use simplified model to either ignore or not fully consider the significant impact of pre-existing fractures on hydraulic fracture propagation. Pursuing development of numerical models that can accurately characterize propagation of hydraulic fractures in naturally fractured formations is important to better understand their behavior and optimize their performance.

In this paper, an innovative and efficient modeling approach was developed and implemented which enabled integrated simulation of hydraulic fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff and fluid flow in reservoir. This improves stability and convergence, and increases accuracy, and computational speed. Computing time of one stage treatment with a personal computer is now reduced to 2.2 minutes from 12.5 minutes than using single porosity model.

Parametric studies were then conducted to quantify the effect of horizontal differential stress, natural fracture spacing (the density of pre-existing fractures), matrix permeability and fracture fluid viscosity on the geometry of the hydraulic fracture network. Using the knowledge learned from the parametric studies, the fracture-reservoir contact area is investigated and the method to increase this factor is suggested. This new knowledge helps us understand and improve the stimulation of naturally fractured unconventional reservoirs.
A Fast and Robust Technique for Accurate Measurement of the Organic-Rich Shales Characteristics under Steady-State Conditions
Authors: Zamirian M. , Aminian K. , Fathi E. , Ameri S.
Published: October 2014

This paper introduces a robust and accurate technique for the steady-state permeability and porosity measurements in ultra-low permeability shale core samples. A laboratory set-up was designed and assembled which has a resolution of one nano-darcy for the permeability and one-hundredth cubic centimeters for pore volume measurements. Extremely accurate differential-pressure transducers are used to measure the flow of gas passing through the core sample under in-situ conditions. The in-situ conditions are achieved by maintaining isothermal conditions and the application of the confining stress on the core sample. The laboratory set-up is fully automated to eliminate any human error and more importantly maintains the temperature stable within the enclosed unit.

A series of measurements were performed on a Marcellus Shale core sample under wide range of pore and confining pressures using Helium (He) as a non-adsorbent and Nitrogen (N2) and Carbon Dioxide (CO2) as adsorbent gases. The measured gas permeability under steady-state condition is generally higher than the absolute permeability due to gas slippage (Klinkenberg 1941). Recent experimental and numerical studies indicate that permeability values for organic rich shale obtained by using different gases are much larger than the absolute permeability predicted by Klinkenberg the slippage theory. In ultra-tight formations such as organic rich shale, the measured "apparent" permeability is not a linear function of reciprocal of pressure as predicted by Klinkenberg. Thus, a new method based on the double gas slippage theory in nano-capillaries has been proposed for reliable estimation of the shale absolute permeability.

In this study both Klinkenberg and double slippage corrections were applied to the steady-state permeability measurements. The results indicated that application of Klinkenberg to the permeability measurements lead to negative absolute permeability for shale samples. However, the double-slippage correction resulted in physically plausible values for absolute permeability of shale samples. Finally, the measurement results with adsorbent gases indicated that the adsorbed gas layer thickness can significantly impact the gas transport and storage in organic rich shale reservoirs and needs to be considered for hydrocarbon in place calculation and production predictions.
Time-Dependent Initiation of Multiple Hydraulic Fractures in a Formation with Varying Stresses and Strength
Authors: Bunger Andrew P. , Lu Guanyi
Published: October 2014

The premise of classical hydraulic fracture breakdown models is that hydraulic fracture growth can only commence when the wellbore pressure reaches a critical value, sufficient to overcome the tensile strength of the rock. However, rocks are well-known to exhibit static fatigue, that is, delayed failure at stresses below the tensile strength. In this paper we explore the consequences of delayed failure on initiation of multiple hydraulic fractures. Specifically, given a certain breakdown pressure, we investigate the conditions under which subsequent hydraulic fracture(s) can initiate within the timeframe of a stimulation treatment in regions of higher stress and/or strength due to delayed failure mechanisms. The results show that wells completed in shallower formations are more sensitive to variations in strength while wells completed in deeper formations are more sensitive to variations in stress. Furthermore, cases in which all hydraulic fractures breakdown according to the same pressurization regime, that is, all are "fast" (non-fluid-penetrating) pressurization or else all are "slow" (fluid-penetrating) pressurization cases, are highly sensitive to small stress/strength variability. On the other hand, if the first hydraulic fracture initiation is in the "fast" pressurization regime and subsequent fracture(s) are in the "slow" pressurization regime, then the system is robust to a much higher degree of variability in stress/strength. Practically, this work implies that methods aimed at moderately reducing the variability in stress/strength among the possible initiation points (i.e. perforation clusters) within a particular stage can have a strong impact on whether multiple hydraulic fractures will initiate. Additionally, this analysis implies that pumping strategies that encourage "fast", non-penetrative breakdown of the first initiation point followed by the opportunity for fluid-penetrating, "slow" breakdown of subsequent initiation points could be highly effective at encouraging multiple hydraulic fracture initiation.
Innovative Method of Analyzing the Dynamic Behavior of PDC Bits on Bent Motor BHAs Results in Improved Drilling Performance in the Marcellus Shale Play
Authors: Mortimer Laurence
Published: October 2014

Horizontal drilling and hydraulic fracturing are commonplace in the shale plays across the United States with successful wells efficiently yielding large volumes of shale gas and oil at minimum time and cost. Typical well profiles involve building a curve and then drilling long horizontal sections to TD, with the horizontal section taking up to 7000ft to complete. One of the most cost effective means to drill such wells is with Positive Displacement Motor (PDM) Bottom Hole Assemblies (BHAs) consisting of PDMs with bend angles for directional control.

When addressing drilling efficiency; a major contributor is BHA selection and the ability to select the most efficient combination of bit, PDM and stabilizer arrangement for each specific application. It is this selection process that forms the basis of this paper which details how a new suite of analysis tools were developed to analyse the dynamic behavior of a PDC bit on PDMs with variable bend angles and stabilizer configurations. Drilling on a bent motor in rotational mode has long proven challenging for both PDM and bit and the complex dynamic behavior has rarely been fully understood let alone analyzed.

At the heart of the new suite of tools is the capability to analyse the complex trajectory of the cutting structure of the bit to simulate the Bottom Hole Pattern (BHP) created in the rock. Having understood the transient behavior of the bit, an analysis tool was then developed to analyse the drilling behavior of the bit and BHA which resulted in a new approach to PDC bit design for bent motor BHA applications with the design intent of providing smoother drilling, increased durability and higher rates of penetration.

The first run of the new design of bit resulted in improved drilling performance, allowing the customer to drill the complete section to TD using a 2.38° bent motor BHA for the first time in the Marcellus. The negated need for multiple trips ultimately saved the customer up to 25% in completion time resulting in a cost saving of approximately $128k.
Acid Gas Prediction Methodology, Result of Steam Injection Implementation in Heavy Oil Reservoirs
Authors: Lizcano Q. Cesar
Published: October 2014

The increase in the value of crude oil and the insatiable need for energy sources have been an incentive to develop and promote technologies related to the extraction of heavy oil, especially thermal recovery methods. Currently, Thermal methods are being implemented in the Orinoco Oil Belt and it is important to know and be aware of the impact of these kinds of technologies in the field. The following investigation focuses on the development of a methodology for predicting acid gas volumes, Carbon Dioxide (CO2) and Hydrogen Sulfide (H2S), produced by the effect of aquathermolysis reactions of heavy oil with API° 7, in steam injection conditions, using a numerical simulator. This research is based on defining the kinetic parameters of the aquathermolysis reactions through laboratory batch tests carried out in a core from Boyacá block. The aquathermolysis reactions was charged in a numerical simulator using the laboratory data in order to compare the acid gas volume obtained from steam stimulation of extra heavy crude oils and adjust the kinetic parameters of the reactions and take them to a field scale. Finally, multiple simulations with different steam injection techniques are performed, such as cyclic and continuous steam stimulation in horizontals wells, varying also kinetic parameters and steam injection parameters, to determine which exploitation scenario will have the best behavior, and how to manage the acid gas emissions in this kind of reservoirs. In this way, This methodology can be a important tool to obtain acid gas volumes according to the reality of the reservoir, contributing extensively on the reservoir management due to avoid undersizing or oversizing steam injection projects, having an impact on profitability and environmental protection.