bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemically Enhanced Proppant Transport
Authors: Boyer Jeff , Maley Darren , O'Neil Bill
Published: October 2014

Slick water hydraulic fracturing treatments are the preferred method for tight shale plays as they enhance the complexity of fracture networks that are needed to produce economic wells in unconventional formations. At their most basic, these treatments use a polyacrylamide friction reducer to allow for higher pumping rates, but may also include additives such as clay controls, flowback enhancers, scale inhibitors and others. Although traditional slick water treatments are effective, they are limited on several factors that would improve production and - potentially - decrease the cost of a treatment. Such limitations include poor proppant carrying capacity, inconsistent proppant pack distribution, and excessive water volume requirements. Modifying the treatment design of a traditional slick water by adding a novel chemical to the proppant and 5-20% nitrogen, the limitations of this type of stimulation fluid can be reduced.

Improving the performance of the slick water treatment is completed by modifying the proppant's surface properties. A novel surfactant preferentially coats the surface of the proppant (including ceramics and resin-coated proppants), hydrophobically modifying the surface of the solids. The enhanced surface properties of the proppant creates an attraction between the proppant surface and nitrogen gas, in effect, surrounding the particle with a thin layer of gas and thus increasing the buoyancy of the proppant in water. These enhanced properties allow for improved proppant distribution, deeper proppant penetration within the complex fracture network, increased proppant pack volume, and increased maximum proppant concentration that can be placed. Improving proppant placement and increasing the volume that the proppant occupies within the fracture enhances the extent of the conductive fracture network, improving the productivity of the well.

Laboratory results of regain conductivity, flow model, and sand suspension testing will be presented. A field case study will be provided based on treatments that were pumped in the Cardium formation in the Western Canadian Sedimentary Basin. The case study will illustrate how operational efficiencies and cost savings are possible without affecting production. Advantages include using less water while minimizing the occurrence of screenouts. Data will show that by adding this new technology to treat the proppant, production was enhanced significantly, greater than 30% in the case study provided.
Systems Modeling and Design of Automated Directional Drilling Systems
Authors: Downton G C
Published: October 2014

A simple technique has been devised for gaining insight into the directional performance of a wide range of drilling systems. The software for simulating the directional behavior of drilling tools has reached a high level of technical sophistication. However, this has not rendered the analytical path redundant. The role of the computer is vital to both approaches. In the former, it is the immense number-crunching power, and in the latter, it is an ability to search for an explanation of what the complex mathematical forms actually mean.

The technique employed will be accessible to engineers with a basic understanding of circuit analysis. The lateral borehole propagation response of a wide class of directional drilling is derived as a simple, first-order delay differential equation. The "delayed" part of the expression is determined by the contact points of the bottomhole assembly (BHA) with the borehole. With this insight, a succinct and intuitive method for constructing the transfer-function response of a drilling system's directional tendency consequent upon the influence of gravity, weight on bit (WOB), and active steering actuator influences will be explored. The analytical approach gives simple algebraic forms for a tool's dogleg capability and leads to simple graphical techniques for determining if the trajectory will be smooth or spiraled.

The directional capability of passive BHAs to build, drop, or hold is considered first as a springboard to analyze today's rotary steerable systems (RSS) wherein the strength of the steering actuation overshadows the BHA's inherent gravity-induced directional tendency. This leads to an understanding of how closing the loop around a directional drilling system will impact the performance of a wider automated steering system.
North Cross Devonian Unit - A Mature Continuous CO2 Flood Beyond 200% HCPV Injection
Authors: Aryana Saman A. , Barclay Curtis , Liu Shunhua
Published: October 2014

The North Cross (Devonian) Unit, currently operated by Occidental Oil and Gas, was discovered in 1944. The field was developed using regular 40 acre spacing and produced under primary recovery until 1964. Subsequently, a partial pressure maintenance program was constituted to inject residue gas in an updip location in the field. Large-scale continuous CO2 injection began in April 1972 and was expanded over time to provide CO2 support throughout the field. The field has been under continuous CO2 flood for over four decades. Currently, over 200% hydrocarbon pore volume (HCPV) of CO2 has been injected, and over 60% of the latest estimate of its target original-oil-in-place (OOIP) has been recovered. The field continues to perform well with a gross utilization (MCF CO2 injected/bbl oil recovered) of approximately 30 MCF/BO (20 MCF/BOE). North Cross is an excellent example of a successful mature continuous CO2 flood.
Data-Driven Reservoir Management of a Giant Mature Oilfield in the Middle East
Authors: Mohaghegh S. D. , Gaskari R. , Maysami M. , Khazaeni Y.
Published: October 2014

A novel approach to reservoir management applied to a mature giant oilfield in the Middle East is presented. This is a prolific brown field producing from multiple horizons with production data going back to mid-1970s. Periphery water injection in this filed started in mid-1980s. The field includes more than 400 producers and injectors. The production wells are deviated (slanted) or horizontal and have been completed in multiple formations.

An empirical, full field reservoir management technology, based on a data-driven reservoir model was used for this study. The model was conditioned to all available types of field data (measurements) such as production and injection history, well configurations, well-head pressure, completion details, well logs, core analysis, time-lapse saturation logs, and well tests. The well tests were used to estimates the static reservoir pressure as a function of space and time. Time-lapse saturation (Pulse-Neutron) logs were available for a large number of wells indicating the state of water saturation in multiple locations in the reservoir at different times.

The data-driven, full field model was trained and history matched using machine learning technology based on data from all wells between 1975 and 2001. The history matched model was deployed in predictive mode to generate (forecast) production from 2002 to 2010 and the results was compared with historical production (Blind History Match). Finally future production from the field (2011 to 2014) was forecasted. The main challenge in this study was to simultaneously history match static reservoir pressure, water saturation and production rates (constraining well-head pressure) for all the wells in the field.

History matches on a well-by-well basis and for the entire asset is presented. The quality of the matches clearly demonstrates the value that can be added to any given asset using pattern recognition technologies to build empirical reservoir management tools. This model was used to identify infill locations and water injection schedule in this field.
A Statistical Evaluation of Cement Placement Techniques by use of Cement Bond Index
Authors: Pallapothu Surya , Bogaerts Martijn , DeBruijn Gunnar , Peyle Sebastien , Rashid Faisal
Published: October 2014

Cement placement plays an important role in the primary cementing process. There are several best practices in place which are believed to have significant impact on the quality of the overall cement job. Previous investigations suggest that a combination of multiple placement techniques, such as density and rheology gradient coupled with proper displacement rates, pipe rotation or reciprocation, conditioning of drilling fluid prior to cement job, pipe centralization, and bottom plugs, improves the chances of a successful cement job. However, there is little quantitative analysis available to demonstrate the importance of each technique independently in the field.

In the past 15 years, operations in offshore Atlantic Canada have cemented 140-mm and 178-mm liners in 216-mm openhole sections in two different reservoirs. The cementing designs for the liners are similar, especially in terms of flow rate, centralization (type or placement), and spacer train, but differ in pipe rotation, mud conditioning, and bottom plugs. Once the cementation process is executed, it is evaluated by an ultrasonic imaging tool, which measures the acoustic impedance to calculate the cement bond index. The average of the cement bond index for the entire liner is then used to quantify the quality of the cement job for each well.

The average cement bond index obtained from 53 wells was used to evaluate various cement placement techniques. The average cement bond index is proportional to the amount of cement bonded to the pipe and is inferred to be proportional to factors related to mud removal and cement placement. Factors that affect mud removal, such as mud conditioning, annular velocity, pipe movement, wellbore characteristics, and the presence of a bottom plug, are investigated. Statistical analysis of the cement bond index indicates that some of these cement placement techniques affect mud removal significantly more than others. A comprehensive analysis of these results and an assessment of potential benefits are presented in this study. The results of the study were used to improve the cement job design.
Vapor-Liquid and Liquid-Liquid Interfacial Tension of Water and Hydrocarbon Systems at Representative Reservoir Conditions: Experimental and Modelling Results
Authors: Pereira Luis M. , Chapoy Antonin , Tohidi Bahman
Published: October 2014

In this paper, interfacial tension (IFT) of two ternary water-rich hydrocarbon systems were investigated at a representative reservoir temperature of 150 °C and equilibrium pressures up to 140 MPa. Two-phase and three-phase IFT measurements of water-methane-hexadecane and water-methane-toluene mixtures were carried out in our previously validated Pendant Drop facility and the equilibrium phase densities, required to determine pertinent IFT values, were determined by measuring the volume and mass of samples separately. The results showed a high pressure dependency of IFT values below the hydrocarbon dew point (i.e., three-phase region) whereas a slight increase on the interfacial tension was observed in the two-phase region.

Aiming at developing a general model for describing this property in multiphase systems, the generated and literature IFT data were used to develop and validate our model based on the Linear Gradient Theory (LGT). The LGT has been proven capable of describing vapor-liquid and liquid-liquid interfaces in systems containing polar and non-polar compounds when coupled with an appropriate thermodynamic model. In this work the LGT was coupled with the Cubic-Plus-Association equation of state (CPA EoS) for a correct description of the equilibrium properties of the phases involved. The modelling results confirmed the superiority of the LGT over classical models in that one single model can be used for describing the IFT of multiphase systems with greater accuracy.
Securely Managing Video-Rich Data in Control Rooms and Real-Time Operating Centers with Fiber Optic Systems
Authors: Fanguy Darrel , Wachter Larry
Published: October 2014

The oil and gas industry faces a multitude of complex business challenges. Asset Integrity Management (AIM) is an overarching approach designed to address the challenges by getting people, processes and technology working together to improve productivity, safety and security, while also protecting the environment.

The AIM objectives of improved asset productivity, process safety and protecting the environment are closely intertwined and often at odds. For instance, in drilling operations, new technologies are continuously improving the speed of drilling. But that speed can add to wellbore instability and increase the chance of a serious process safety and environmentally dangerous event. Ironically, such an event might eliminate all efficiencies gained from the new technology and more. 1 The underlying signal extension and switching systems required for distributing and improving staff collaboration, enhancing the quality of decision-making, maintaining safety, and meeting the core objectives of AIM.

In support of AIM, the nature of what was previously known as a "Control Room" has changed dramatically. In today's digital oilfield, the traditional control room has evolved to a multi-faceted facility more commonly known as a "Real-Time Operating Centre" or RTOC. A RTOC is exponentially more data rich, evolving to include high-resolution video and audio surveillance.

This paper explores key issues in the design of secure, high performance KVM (keyboard, video and mouse) signal extension and switching systems for the distribution and management of video rich data in control rooms and real-time operating centres. It describes system alternatives from several perspectives, including: the diversity and distance of sources and destinations of information, performance requirements, physical security of the system and the information, management of user access, system reliability and redundancy, flexibility and scalability, and ultimately control room and real time operating centre productivity.
Using Distributed Acoustic Sensors to Optimize Production in Intelligent Wells
Authors: Bukhamsin Ahmed , Horne Roland
Published: October 2014

As many fields around the world are reaching maturity, several drilling and completion technologies have been developed to boost production from these fields. Smart completions and distributed measurements are two of the most important tools in this category. This study examined a new smart completion tool, Distributed Acoustic Sensor (DAS) in terms of its utility for inflow monitoring and optimization in smart wells.

We began by evaluating the performance of DAS as a tool for measuring downhole multiphase flowrate. A description of the methodology to calculate individual phase flowrates from acoustic signals, caused by pressure fluctuations in the flow, is presented. As DAS provides continuous flow of data from the wellbore, another opportunity emerges to optimize the flow from these smart wells. A methodology to use calculated downhole flowrates to update existing simulation models and perform, near real-time optimization is suggested for wells installed with DAS. As opposed to conventional optimization methods that rely only on reservoir simulation models, this procedure also makes use of real-time flow measurements. The methodology was tested on a synthetic model with encouraging results, where the optimum solutions obtained were in close agreement to the true optimum.

The flow profiling procedure was applied to several actual wells. The first well was a single-phase oil producer. This process yielded speed of sound results that matched the fluid properties obtained in the lab. Flowrates from different segments of the well were calculated and results were in close agreement with a surface flowmeter for most sections of the well. More examples were conducted in two-phase flow wells with results being more qualitative and less conclusive. When the optimization procedure was applied for synthetic cases that have wells with similar completions to the tested ones, results showed that significant value could be realized by incorporating real-time measurements in the optimization process.

Several advantages could be realized with the application of these methods. First, continuous downhole flow monitoring provides asset managers with more accurate allocation of their wells. Second, more accurate modeling for wellbore flow is possible by using in-situ phase flows to calibrate existing models. With more accurate models, evaluating different flow scenarios is possible before applying them on the field. Finally, quick decisions to change the controls of the well are easier with the described optimization method. By comparison, full reservoir simulation model optimization takes a very long time to make their use practical in everyday applications.
Effect of Confinement on PVT Properties of Hydrocarbons in Shale Reservoirs
Authors: Pitakbunkate T. , Balbuena P. B. , Moridis G. J. , Blasingame T. A.
Published: October 2014

Shale reservoirs play an important role as a future energy resource of the United States. Numerous studies have been performed to describe the storage and transport of hydrocarbons through ultra-small pores in the shale reservoirs. Most of these studies were developed by modifying techniques used for conventional reservoirs. The common pore size distribution of the shale reservoirs is approximately 1-20 nm and in such confined spaces the interactions between the wall of the container (i.e., the shale and kerogen) and the contained fluids (i.e., the hydrocarbon fluids and water) may exert significant influence on the localized phase behavior. We believe this is due to the fact that the orientation and distribution of fluid molecules in the confined space are different from those of the bulk fluid; causing changes in the localized thermodynamic properties.

This study provides a detailed account of the changes of PVT properties and phase behavior (specifically, the phase diagrams) in a synthetic shale reservoir for pure hydrocarbons (methane and ethane) and a simple methane-ethane (binary) mixture. Grand Canonical Monte Carlo (GCMC) simulations are performed to study the effect of confinement on the fluid properties. A graphite slab made of two layers is used to represent kerogen in the shale reservoirs. The separation between the two layers, representing a kerogen pore, is varied from 1 nm to 10 nm to observe the changes of the hydrocarbon fluid properties. In this paper, the critical properties of methane and ethane as well as the methane-ethane mixture phase diagrams in different pore sizes are derived from the GCMC simulations. In addition, the GCMC simulations are used to investigate the deviations of the fluid densities in the confined space from those of the bulk fluids at reservoirs conditions. While not investigated in this work, such deviations may indicate that significant errors for production forecasting and reserve estimation in shale reservoirs may occur if the (typical) bulk densities are used in reservoir engineering calculations.
Upstream Offshore Facility Weight Growth Study
Authors: Rui Ray (Zhenhua) , Walker Jason
Published: October 2014

Offshore facility weight is significantly related to the cost, schedule, and complexity of offshore facility projects. Therefore, controlling offshore facilities weight growth is important to project success. This paper sought to understand weight growth among different project phases and its causes. Using Independent Project Analysis, Inc.'s (IPA's) detailed database of oil and gas projects, we conducted a rigorous statistical analysis of offshore weight growth to identify the root cause(s). This paper evaluates the offshore facilities weight growth for 153 global offshore projects at the end of the concept selection and authorization gates. The study results show that industry weight growth is much higher than expected. Although Industry typically allocates 13 percent of dry weight for weight contingency at the end of Front-End Loading (FEL) 2 and 6 percent of dry weight at authorization to account for unexpected weight growth, half of the topsides had more than 10 percent weight growth, and more than one in three substructures had more than 10 percent weight growth from authorization to completion. There is a large gap between the estimated weight contingency and the actual amount spent for these projects. This analysis shows that most offshore facilities weight growth is caused by poor engineering status for the facilities at authorization. The analysis also shows that setting aggressive schedule targets erodes the benefits of good engineering definition. In general, projects with good engineering and aggressive schedule targets have an extra 9 percent weight growth compared to projects with good engineering and non-aggressive schedule targets. Offshore facilities weight growth was found across many different offshore facility concepts (e.g., fixed platforms, spars, tension-leg platforms, etc.). This research provides an understanding of industry offshore facilities weight performance and the main causes of weight growth, and offers recommendations for improving weight predictability.
Simulation of Asphaltene Precipitation during Gas Injection Using PC-SAFT EOS
Authors: Mohebbinia Saeedeh , Sepehrnoori Kamy , Korrani Aboulghasem Kazemi , Johns Russell T.
Published: October 2014

Oilfield problems owing to asphaltene precipitation are well known. Asphaltenes can block pore throats or change the formation wettability and thereby reduce the hydrocarbon mobility. Simulation of asphaltene precipitation during gas injection requires a comprehensive thermodynamic model, which accounts for the complex phase behavior of asphaltenes. In this paper, PC-SAFT EOS is implemented for the first time in a compositional reservoir simulator to model asphaltene precipitation. The additional computational time of PC-SAFT compared to the cubic equations-of-state such as Pen-Robinson (PR EOS) is decreased by improving its root finding algorithm. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate the dynamics of precipitated asphaltenes. Different gas injection scenarios are modeled to show the effect of gas injection on apshaltene precipitation and deposition.

Simulation results show that the profile of the damaged area by asphaltene deposition is governed by the shape of the asphaltene precipitation envelope for the reservoir fluid. The damage caused by asphaltene deposition, through plugging and wettability alteration, was revealed as a decline in productivity index curves. Results indicate that a reservoir fluid can have precipitation risk during gas injection even if it does not exhibit precipitation in the primary recovery life of a field. The computational time of the simulations using PC-SAFT EOS were compared to those using PR EOS for different number of components. Results of these comparisons show the feasibility of using PC-SAFT in compositional simulations.
Continuous High-Frequency Measurements of the Drilling Process Provide New Insights into Drilling System Response and Transitions between Vibration Modes
Authors: Bowler Adam , Logesparan Lojini , Sugiura Junichi , Jeffryes Ben , Harmer Richard , Ignova Maja
Published: October 2014

The oil and gas industry has become increasingly interested in drilling dynamics and vibration as causes of drilling inefficiency and reduced drilling performance. Generally, drillstring vibration is measured with shock-and-vibration sensors installed in measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, and rotary steerable systems (RSS). Although these tools provide valuable real-time and recorded-mode information on the dynamic conditions, they are not generally designed to capture continuous high-frequency mechanics and dynamics data, and burst data may miss important information about the evolution of the system response and state.

A downhole mechanics measurement tool has been developed that makes a comprehensive suite of measurements of the drilling process, including forces, accelerations, rotational speed, pressures, and temperatures. In addition to providing information in real-time, the tool has the capability to capture long durations of continuous data at frequencies between 50 and 2,000 Hz. The recorded-mode information obtained has provided significant insight into the response of the drilling system to initiating rotation; drilling procedures and parameter modifications; and exposure to excitation from sources including, but not limited to, rig heave, bottomhole assembly (BHA) component imbalance, and bit-rock interaction. A wide range of occurrences has been captured in which the drilling system switches from a dominant vibration mode, typically torsional (downhole rotation-velocity oscillations or stick/slip) into a different mode, such as axial (bit bounce) or lateral (whirl). Transitions between different types of whirl have also been recorded.

Several cases were studied to investigate the evolution and response of drilling system behavior based on the in-depth interpretation of relatively long durations (minutes to hours) of high-frequency data sets in the operational context. The findings verify the value of using continuous high-frequency vibration data to understand the drilling system and increase drilling performance.
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase II: Diagnostic Testing and Initial Results
Authors: Norris S. O. , Scherlin J. M. , Mukherjee J. , Vanderwal P. G. , Abbas S. , Nguyen Q. P.
Published: October 2014

In a previous paper we described the laboratory work, reservoir simulation, and initial design of a CO2 Foam Pilot in the Salt Creek Field, Natrona County, WY. In this paper, we review the diagnostic testing and initial results from the pilot including: injection rate profile, production data analysis, injection and production logging, chemical tracers, streamline analysis, and reservoir simulation.

Although the CO2 flood has been very successful at Salt Creek, it is recognized that certain isolated patterns have exhibited high CO2 production and inefficient CO2 utilization, most likely due to the channeling of fluids through high permeability, low volume zones (fractures, thief zones, etc.) and the gravity over-ride of the injected fluids. Accordingly, a foam pilot was initiated to test the ability of CO2 to remediate these conditions.

A change in the injection well rate (at constant surface injection pressure) was the first indicator to be observed; the injection rate decreased by approximately 40%, indicating a strong mobility reduction of the CO2 in the reservoir. Production and injection profile logs were run before and after surfactant injection, and a change in profile was observed in one producer. Chemical tracers were injected in both the gas and water phases before and after surfactant injection; results indicate that CO2 was diverted from high permeability, low volume conduits, such as fractures. An analysis of the production data for the four offset producers show a definite increase in liquid production and a corresponding decrease in GLR (gas-liquid-ratio.) Streamline analysis suggest areal diversion of CO2 over time. Finally, reservoir simulation prediction cases are given and discussed.

CO2 flooding has become a standard EOR technique for many water-flooded fields. Methods for increasing the efficiency of these floods, such as the use of CO2 foam, can add great value.
Early Kick Detection Methods and Technologies
Authors: Fraser D. , Lindley R. , Moore D. , Vander Staak M.
Published: October 2014

Early Kick Detection (EKD) is one of the most important areas for improvement in well control safety. The need for earlier, more accurate, more reliable kick detection across a wide range of drilling operations has become increasingly important as more operations are being conducted in deep water with increasingly tight pressure margins. In order to accomplish this, it is important to start measuring the indicators that have the greatest impact. This paper identifies and proposes two risk based Key Performance Indicators (KPIs) related to kicks: how long it takes to positively identify a kick, and how long it takes to respond to a kick once the identification is made. These KPIs are the Kick Detection Volume (KDV) and the Kick Response Time (KRT) respectively. They provide the ability to directly measure kick detection and management approaches. A third metric, the Drilling Mode Kick Frequency (DMKF), while not a performance indicator, is critical to help determine the point at which drilling operation kicks are most likely to occur and thereby to aid in the evaluation of kick detection methodologies. This paper discusses and compares technical approaches to early kick detection including how they relate to safety, efficiency, and reliability over a range of common deep water operations. By identifying "actionable" indications of a kick, a general approach is suggested to help focus on technologies leading to the most likely improvements for EKD. Irrespective of the EKD optimization path chosen however, the proposed KPIs can be used to quantitatively evaluate and compare the performance of different technologies and operational strategies.
Theoretical Foundation and Design Formulae for Channel and Pillar Type Propped Fractures – A Method to Increase Fracture Conductivity
Authors: Meyer Bruce R. , Bazan Lucas W. , Walls Doug E. , Brinzer Bill C.
Published: October 2014

A mathematical formulation and solution methodology for placing proppant to create open channels and propped pillar packs in hydraulic fractures is presented. The advantage of this methodology is increased fracture conductivity by creating open channels and/or pillars that support the unpropped (or open) fracture region. The technique requires reduced proppant mass and results in enhanced fracture conductivity. The work illustrates that high conductivity proppant is not required.

The paper presents the governing equations, assumptions and a solution methodology for designing open channels and for flow around pillars in propped fractures. The governing equations and assumptions for calculating the surface displacement (in the loaded and unloaded regions) for pressure loading of a strip and circular region in an elastic half-space are formulated in the appendices. Four cases are presented: 1) uniform pressure distribution over an infinite strip, 2) uniform (constant) distribution (i.e., rigid line punch) over an infinite strip, 3) uniform pressure applied to a circular region, and 4) uniform normal displacement over a circular region.

The effects of the closure stress on the proppant and the formation modulus on embedment are discussed and illustrate the advantage of this methodology in formations with high Young's modulus and low confining stress contrasts. Disadvantages and limitations of the procedure are also discussed. A formulation for the equivalent fracture permeability for flow through channel and pillar type propped fractures is also presented and demonstrates the advantage of creating pillars and open channels for enhanced fracture conductivity. Fractures with open channels and pillars have much greater permeability than traditionally propped fractures. However, proppant permeability is not important in pillar and channel type fracture designs. A proppant that is more ductile and one that creates few fines when crushed is more advantageous for channel and pillar type designs.

The design formulae present a simple methodology to allow for easy field implementation based on a volumetric ratio of fluid to proppant stages. The treatment design can be accomplished with standard industry pumping equipment and methods are provided for the fracture design engineer to create treatment schedules that can be employed by current hydraulic pumping technology. The methodology, if implemented correctly, will greatly increase the dimensionless fracture conductivity (by orders of magnitude) resulting in enhanced production while minimizing operational costs associated with proppant quality.
"Slick Water Fracturing and Small Proppant" The future of stimulation or a slippery slope?
Authors: Ely John W. , Fowler Steven A. , Tiner Robert L. , Aro Dustin J. , Sicard George R. , Sigman Tanner A.
Published: October 2014

Over the past 10 years Ely Corp has supervised more than 100,000 "Slick Water Fracture treatments". After more than 30 years of dominance by extremely viscous crosslinked gels, viscous oils, emulsions and foams, the industry has in selection of fracturing fluids, moved to the point that the vast majority of fracturing fluids are either water and friction reducer or combinations of linear gel and or crosslinked gel that is very rapidly degraded to water once in the formation. In a similar time frame our industry has moved rapidly away from specific selection criteria of proppant based on strength under closure and conductivity profiles which were enhanced by both size, particle distribution, and inherent strength. The dominate proppants now used in the industry are smaller proppant such as 40/70 and 70/140 (100 mesh).

The switch to thin fluids was mainly because of intense efforts from individuals such as George Mitchell and other innovative companies who steadfastly believed in the potential of producing from virtually impermeable matrix source rock and were open to try any available technology. The switch to small proppant was driven in most cases by the lack of transport capability of the thin fluids, and in many cases due to lack of available higher strength proppant.

The success of these slick water frac fluids has, in our opinion, been due to creating a drastically different geometry combined with much larger volumes. The type of frac fluids described have been present in the history certainly since the 50's but not with comparable rate and volume and typically not with the dominate proppant being 40/70 or smaller.

The paper will, utilizing our data base and public production data, illustrate what has truly changed the dynamic of fracturing in our industry. We will also illustrate techniques to optimize slick water fracs based on a combination of new generation technology and experience in not only source rock shale but many so called conventional reservoirs which have only now become economical with use of high volume slick water treatments where more conventional viscous fluids failed.

Based on the broad success of these fluids, we will propose a hypothesis for why these fluids and proppants, which defy conventional frac theory, have made the industry more closely evaluate even the most basic frac theories that we have followed for multiple decades.
Optimizing Hydraulic Fracture Performance in the Liquids-Rich Eagle Ford Shale - How Much Proppant Is Enough?
Authors: Al-Tailji Wadhah , Smith Nick , Shelley Robert
Published: October 2014

Multi-stage hydraulic fracturing has been implemented in conjunction with horizontal drilling in order to make unconventional, low-permeability reservoirs economically viable. Earlier studies from the development of the Barnett Shale have suggested that high fluid volumes and low proppant concentrations were necessary to generate sufficient stimulated reservoir volume (SRV). However, other shale plays, including the Eagle Ford, have formation material with higher ductility and exist in an anisotropic stress environment that tend to generate planar fractures, where lower fluid volumes and higher proppant concentrations are more appropriate.

One operator began exploring their Eagle Ford acreage by utilizing sliding sleeve systems in cemented casing, while trying to determine the best depth within the Eagle Ford sequence to target. Once the drilling target was decided upon, the operator transitioned to a plug-and-perf type of completion in cemented casing in order to improve formation contact and recovery. This provided an opportunity to evaluate different completion designs with enough variability in the data to evaluate fracture performance.

This paper will explain the process used to evaluate drilling, completion, and production information in order to discover the parameters that have the highest influence on well productivity. Completion parameters were evaluated against production performance in a variety of ways, including bivariate, multivariate statistical analysis, and neural network modeling. One parameter that was discovered to have high impact was the amount of proppant used per effective cluster, and the data indicated that more proppant was required than what prior experiences in shale stimulations suggested. Changes to the completion and stimulation design were made based on this analysis, resulting in improved production results.

This study was useful in that it helped identify new ways to evaluate completion and production data in the liquids-rich Eagle Ford Shale, particularly in evaluating fracture performance by normalizing by the number of perforation clusters.
Laboratory Investigation of Acoustic Behavior for Flow from Fracture to a Wellbore
Authors: Martinez R. , Chen K. , Santos R. , Hill A. D. , Zhu D.
Published: October 2014

Distributed acoustic sensing (DAS) technology is implemented to monitor downhole audible sounds for fracture diagnosis, leak detection and other applications. While DAS systems have the potential to enhance downhole flow monitoring, its use is currently limited to qualitative interpretation. Future applications of DAS such as distributed flow prediction require quantitative interpretation to determine flow rate, possibly of multiple phases, from acoustic data.

In this paper we use signal processing techniques to determine flow rates from a simulated fractured well. Production into a 5 ½-inch well is simulated by injecting fluid into a fracture. The fracture was originally simulated with a piece of pipe filled with proppant, and then we used a pair of proppant-filled parallel plates with dimensions of 0.2 inch wide, eight inch high, and sixteen inch long, to represent a fracture. Liquid and gas were injected at varying rates into the fracture and into the well. The noise from production was recorded with a hydrophone within the wellbore. Through signal processing, the sound signal collected is transformed into the Fourier domain for insight into the sound spectrum.

Experimental results show that frequency and sound intensity varies with the flow condition. The acoustic signal is sensitive to the flow rate and the type of fluid. The peak frequency indicates the phase of the fluid and its magnitude indicates the flow rate. The frequencies for gas production are in a range distinct from those for liquid production and the sound levels are related to the flow rate for both fluids. Experimental results also show that fracture geometry has an effect on the sound that is generated and sound from production can be used to identify fractures with restricted widths.
Deepwater Gas Zone Shutoffs by Wireline in Openhole Gravel Pack Completions
Authors: Zettner Claudia , Bensmiller Hank , Lane Tom
Published: October 2014

An operating company successfully executed two wireline through tubing gas shutoff (GSO) workovers in high angle openhole gravel pack (OHGP) completions to isolate high gas oil ratio (HGOR) zones, resulting in significantly increased oil production. This paper summarizes the GSO concept, production logging results, completion modeling, job planning, and prejob surface testing of the completion equipment, job execution, and production results.

The GSO workovers were performed on a tension leg platform (TLP) in a deepwater offshore field. Isolation of HGOR zones was achieved by installing a wireline deployed stackable straddle system across the heel of the OHGP interval. Although both wells have OHGP completions for sand control, effective isolation of the gas zone was predicted using completion modeling and was validated by sustained production performance. These wells do not have external casing packers (ECPs) to prevent flow through the gravel pack interval. Isolation of the gas along the annulus is provided only by increased hydraulic resistance in the gravel packed annulus.

The candidate wells had unfavorably HGORs attributed to gas breakthrough from ongoing gas reinjection. To evaluate if production could be improved by reducing gas production, detailed mathematical modeling of an isolation straddle's impact to inflow from the reservoir through the completion was performed. Results suggested that internal isolation could provide effective GSO without ECPs. Optimal straddle length was determined to help minimize production from the HGOR zone without affecting low GOR zones. In preparation for the workovers, multiple surface tests were conducted to test installation and retrieval of the completion equipment as well as integration and function of tools and equipment from multiple service companies. Work on the first well included the first use of coiled tubing (CT) by the operator on a TLP for a workover. After the CT milling of downhole restrictions, 16 components were sequentially installed by means of electric line (e-line) of a stackable straddle system across the high gas zone. After straddle installation, both wells transitioned from being cycled to continuous lower GOR production. The first well produced 5,000 BOPD at 6,000 GOR before the GSO, and was increased to 10,000 BOPD at 1,000 GOR. The second well produced 6,000 BOPD at 6,000 GOR before the GSO, and 10,000 BOPD at 500 GOR afterward.

The keys to success involved strong teamwork and support from multiple service companies using CT milling, completion equipment, wireline, slickline, and conveyance tools. Significant scalability was achieved during planning of the second workover based on observations from the first.
A New Approach for Efficiently Evaluating Highly Permeable Coalbed Methane Reservoirs in Surat Basin, Australia
Authors: Pelling Ross , Thorburn James , Pourabed Hamid Reza , Cheong Boon Cheng , Wun Moh Hsiao , Harfoushian Jack H.
Published: October 2014

Following the first commercial recovery of coal-seam gas (CSG) in the 1990s, the CSG industry in Queensland has grown rapidly due to the abundant reserves (~33 000 PJ) and global demand for LNG. There are currently three LNG export projects under construction on Curtis Island near Gladstone in Queensland, with the first shipment scheduled for middle to late 2014. In preparation for the completion of the first LNG plant, the QCLNG project, operated by QGC, is currently ramping up CSG production in the Surat basin. By the end of 2014, more than 2000 wells will be drilled and connected to the QGC gas-and-water-gathering network, and thousands more are scheduled for drilling and completion in subsequent years of the project. To meet the production target, it is increasingly important for QGC to accurately evaluate the well productivity during the early stage of development to optimise the operation of the field and ensure all LNG contractual agreements are met.

To date, drillstem testing (DST) has been the most common form of evaluating CSG well productivity. However, the improved capabilities of the wireline formation tester (wireline FT) for testing larger coal intervals (between 1 and 15 m) and deriving similar reservoir parameters is making it a popular alternative to the more costly DST. Nevertheless, although facing very few issues in low-permeability coal seams, the wireline FT is unable to create sufficient pressure drawdown in higher permeability coal seams (>100 md) due to the mechanical limit of its downhole pump (<20 B/D). As a result, the wireline FT interval pressure builds up to formation pressure rapidly and stabilises to gauge resolution within the first few minutes. This causes significant uncertainty in the permeability measurement. In view of these wireline FT limitations, operators have been more inclined to evaluate the higher-permeability coal intervals with DST services, therefore motivating wireline service providers to find ways of improving wireline FT capability

This paper describes utilising super flow technique to create sufficient drawdown in highly permeable coals using wireline FT sample chamber module. Superflow simulates closed-chamber DST by using the high volume sample chamber module of the wireline FT tool. Two different superflow techniques have been implemented with positive results. Several superflow tests were compared with conventional drawdown/build-up tests over a number of coal intervals of varying permeability to confirm the validity of the new testing method. The results indicate this technique has extended the wireline FT capabilities to higher permeability coals that have been typically conducted by DST services. The addition of the sample chamber module and corresponding superflow theory, the wireline FT has broadened the range of CSG applications.
Surfactant-Based Fluids Containing Copper-Oxide Nanoparticles for Heavy Oil Viscosity Reduction
Authors: Srinivasan Aditya , Shah Subhash N.
Published: October 2014

Limited research is reported in the area of nano-fluids applicability in heavy oil recovery. Some of the largest reserves in the world are heavy oil reservoirs. Thermal and chemical methods are widely used for heavy oil recovery. This research work investigates the viscosity reduction of heavy oil by adding a surfactant-based fluid containing nanoparticles. The viscosity reducing effect of only the nano-sized copper-oxide particles without surfactant-based fluid on heavy oil is also examined. Copper (II) oxide particles were selected due to their higher thermal conductivity, easy availability, and lower cost compared to metal nanoparticles. Two heavy oil samples (20-21 API°) having different viscosities and acquired from two different wells located in Oklahoma, USA were used for testing. Heavy oil samples mixed with nano-emulsion containing copper-oxide nanoparticles were investigated at different nanoparticle concentration and oil to emulsion volume ratio. Oil to emulsion volume ratio of (1:0.25) was used to determine optimum nanoparticle concentration. The optimum nanoparticle concentration was found to be 0.02% wt., exhibiting the maximum viscosity reduction.The viscosity of oil samples was measured at various temperatures. The performance of this nano-emulsion was also compared to an industrial viscosity reducer. In addition interfacial tension tests were performed with the oil samples. A significant reduction in the interfacial tension of heavy oil was observed after the formation of oil-in-water emulsion. Inherent properties of copper-oxide nanoparticles in tandem with the oil-in-water emulsion might utilize the advantages of both thermal and chemical recovery methods to obtain an enhanced heavy oil viscosity reduction. In conclusion, this nano-emulsion can be an effective oil recovery enhancement option in a heavy oil reservoir.