bluuebunny/crossref_metadata_2025_split huggingface dataset:
How to Achieve and Control Branch Fracturing for Unconventional Reservoirs: Two Novel Multistage-Stimulation Processes
Authors: Stanojcic M. , Rispler K. 
Published: February 2011

Abstract
The successful development and exploitation of unconventional reservoirs has relied on innovative technologies, such as horizontal drilling, multistage completions, modern multistage fracturing, and fracture mapping to pursue economic completions. It is important to highlight that economic production in these ultralow matrix-permeability reservoirs relies on conductivity that must be generated through hydraulic fractures and fracture-network systems. Simulations demonstrate that shale reservoirs with ultralow permeability require an interconnected fracture network of moderate conductivity (branch fractures) with relatively small spacing between fractures to obtain economic production rates and reasonable recovery factors. This paper discusses two recently developed hydraulic fracturing processes to improve economic recovery in unconventional reservoirs.
The first new process is designed for multistage-fracturing treatments with high pumping rates and low proppant concentration. This method uses the efficiencies of tubing-deployed abrasive perforating. Proppant slurries are then pumped down the coiled tubing (CT) and nonabrasive clean fluid is pumped down the annulus, saving the permanent tubulars from erosion. As a result, the rate down the annulus can be much higher. The pumping rate can be instantly manipulated to customize the placement and concentration of proppant being pumped down the CT. In case of premature screenout, a well could be easily reverse-circulated and cleaned for the next stage. Wellbore proppant plugs eliminate the need for overflushing, and the new approach to fracture stimulation, known as branch fracturing, could be achieved by changing proppant concentration in real time.
The second new process uses a combination of mechanically activated sleeve completions and fracturing of individual intervals with a change in the sequence in which the intervals are stimulated. This new method is proposed with the goal of altering the stress in the rock to facilitate branch fracturing and to connect to induced stress-relief fractures in a single, horizontal well.
Calculating Pump Fillage for Well Control Using Transfer Point Location
Authors: Ehimeakhe Victoria 
Published: February 2011

Abstract
Knowing correct pump fillage is pivotal in well control as well as in estimating pump efficiency and thereby optimizing the production of a beam pumping well. The pump fillage is often approximated from the graphical representation of the downhole card, which can sometimes be inaccurate.
This paper focuses on a method to compute pump fillage using downhole position versus time and load versus time data either calculated from the measured surface data or measured by a downhole dynamometer. Accurately calculating the pump fillage involves correctly locating the transfer point, the point at which the load is transferred from the standing valve to the traveling valve.
This paper proposes a method comprised of four algorithms to locate the transfer point. The combination of these methods correctly locates the transfer point, accurately determines the pump fillage and therefore optimizes well control and production. Results from application of the method over numerous data sets covering a wide range of conditions are discussed and they demonstrate effectiveness of the method for optimization of beam well assets.
Heavy Oil and Bitumen Recovery Using Radiofrequency Electromagnetic Irradiation and Electrical Heating: Theoretical Analysis and Field Scale Observations
Authors: Davletbaev Alfred , Kovaleva Liana , Babadagli Tayfun , Minnigalimov Rais 
Published: February 2011

Abstract
Heavy-oil and bitumen recovery from difficult geological media such as deep, heterogeneous and high shale content sands and carbonates, and oilshale reservoirs requires techniques other than conventional thermal and miscible injection methods. Materials in oil reservoirs (formation water, crude oil, oil-water emulsions, bitumen and their components like resins, asphaltenes, and paraffin) are non-magnetic dielectric materials with low electrical conductivity. If the electromagnetic field can be created to change these properties, electro-thermo controlled hydrodynamics could improve the displacement and recovery of heavy-oil/bitumen.
This paper deals with the recovery improvement of heavy-oil/bitumen by Radio-Frequency (RF) Electromagnetic (EM) radiation. The RF-EM fields in the form of waves can penetrate deeply enough - from fractions of a meter to several hundred meters - into oil and gas containing reservoirs to generate heat and eventually improve recovery mainly due to the reduction of oil viscosity. The recovery mechanisms and the dynamics of the RF-EM heating process were analyzed for several field scale applications in Russia. In the Yultimirovskaya tar sand deposits, RF-EM energy was transmitted from the RF-EM generator, located at the surface, into the formation by a coaxial system of the well pipes. Another field example analyzed was the RF-EM stimulation process in several wells of the Mordovo-Karmalskaya tar sands performed in the 1980s. It was observed that the formation was heated to the temperature which was sufficient for injection of oxidant (air) to initiate fire flooding.
Then, a mathematical model of this process was presented with a sample exercise. Some data needed for this exercise were obtained from the field tests evaluated.
Field tests proved the efficiency of the RF-EM stimulation of heavy oil / bitumen deposits with low water cut values (in operating production wells with water cut &lt;30% on early field development stages). Numerical simulations suggest that bottomhole temperature and heat/mass transfer effects in the reservoir can be controlled by setting the output performance of the RF generator and by the difference between the reservoir and bottom-hole pressure.
Viscosity of Foamy Oil
Authors: Alshmakhy A. B. , Maini B. B. 
Published: February 2011

Abstract
Foamy oil viscosity is a controversial topic among researchers as to what happens to the apparent oil viscosity when the dispersed gas bubbles start migrating with the oil. For conventional oils, below the true bubble point pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent viscosity of gas-in-oil dispersion remains relatively constant, or perhaps declines slightly between the true bubble point and a characteristic lower pressure, called pseudo bubble point, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead oil value at atmospheric pressure. However, it is a well known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy oil viscosity being lower than the oil viscosity is counterintuitive. The major difference here is the extreme viscosity of the base liquid phase for foamy oil and how this interacts with the gas phase in a porous medium. The reported results appear to be very oil specific in this area, and are also a very strong function of how rapidly pressure is depleted in a given system. It is also likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity due to the size of dispersed bubbles being comparable to the pore sizes.
This study aims to investigate this issue by measuring the foamy oil viscosity under varied conditions. The effect of several parameters, such as shear/flow rate, and gas volume fraction and type of viscometer employed, on foamy oil viscosity was experimentally evaluated. Three different viscosity measurement techniques, including Cambridge viscometer, capillary tube as well as a slim tube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling needle viscometer correlate better with the observed behavior in the slim tube than the capillary viscometer results. Also, unlike live oils, the apparent viscosity of foamy oils was flow rate dependent. Overall, the viscosity of foamy oil was found to be similar to live oil viscosity for a large range of gas volume fraction.
Successful Implementation of Underbalanced Drilling to Maximize Recovery from a Tight Carbonate Reservoir in an Onshore Oil Field, Abu Dhabi, UAE
Authors: Hashemi T A. , Hammadi A. Al , Hammadi D. , Haggag M. , Jeelani O. Al , Bakr S. Al , Laws M. S. 
Published: February 2011

Abstract
Reservoir screening studies were carried out on all of ADCO’s reservoirs to determine their applicability for Underbalanced Drilling (UBD). These studies resulted in a prioritization of potential UBD candidates. The primary business benefits of UBD were determined as follows: –reduction of formation damage ○Productivity Improvement Factors (PIFs) much greater than 1 were determined in many cases;○potential elimination of complicated (and expensive) stimulation jobs.–dynamic reservoir characterization ○improved understanding of geological architecture/flow units and hence the potential for more accurate and reliable reservoir models;○improved completion designs.
Some of the secondary benefits of UBD that were identified beforehand included Rate of Penetration (ROP) improvements while drilling and improved rig performance.
In one field, it was demonstrated that the PIFs per well resulting from UBD would enable fewer wells to be used to develop the field by optimization of the horizontal well length and hence a significant reduction in capital expenditure. From these studies, two fields were selected to carry out initial trials.
This paper describes the lessons learnt from the planning, design and subsequent implementation of UBD in the first well in ADCO, which involved a truly integrated and multi-disciplined team effort. An initial assessment of the business benefits obtained from the trial compared to the results of the initial screening studies is also provided.
Understanding Gas Production Mechanism and Effectiveness of Well Stimulation in the Haynesville Shale Through Reservoir Simulation
Authors: Fan L. , Thompson J. W. , Robinson J. R. 
Published: February 2011

Abstract
A unique workflow and methodology enabled analysis of production data using reservoir simulation to help understand the shale gas production mechanism and the effectiveness of stimulation treatments along the lateral of horizontal wells. Starting from early 2008, we have analyzed production data from more than 30 horizontal wells in the Haynesville Shale using this methodology. This paper presents case studies demonstrating results of this new technique in several different areas of the Haynesville Shale.
After integration of all available data, we built simulation models for the wells stimulated with multistage hydraulic fracture treatments. This modeling work investigates factors and parameters relating to short- and long-term well performance including 1) pore pressure, 2) matrix rock quality, 3) natural fractures, 4) hydraulic fractures, and 5) complex fracture networks. By historymatching the observed production, we have identified the primary factors for creating good early well performance.
The Haynesville study has provided a better understanding of the gas production mechanism and effectiveness of stimulation along the laterals. After calibration of the simulation model, effective well drainage area and reserve potential can be calculated with more confidence. The Haynesville Shale is a very tight source rock. The shale matrix quality correlates with production performance when stimulation treatments are consistent along the lateral. A complex fracture network created during the stimulation treatment is the key to generating superior early well performance in the Haynesville Shale. Knowing how to effectively create more surface area during treatment and preserve the surface area after treatment are critical factors for making better wells in the Haynesville. Operators can use this information to determine where and how to spend resources to produce better wells. It also helps refine expectations for well performance and minimizes the uncertainties of developing these properties. The workflow and methodology have also been successful in other shale plays.
Development of an Integrated Availability Model For ADCO’s Availability Assurance Program
Authors: Santoso Bambang S. 
Published: February 2011

Abstract
ADCO operates and manages an expanding system of on-shore crude oil producing assets in the Emirate of Abu Dhabi – U.A.E. To assess the future Effective Capacity, track the actually achieved Effective Capacity and forecast the Effective Capacity for each forthcoming year, the company employs an Integrated Availability Model.
The model was initially developed in 2002–2003, using a Shell GSI software product called SPARC to assess the future Effective Capacity for an expansion project. Three years later it was further developed for another expansion project. In 2006–2007 the model was upgraded to capture the actual downtime events of individual strings/wells and the critical surface facilities for System Availability tracking purpose. In 2009 the model was further developed to support planning task that includes synchronization / optimization of major shutdowns planning and forecast the Effective Capacity and the System Availability for each forthcoming year.
The assessment, tracking and planning tasks are the core activities of the ADCO’s Availability Assurance Program which objectives include improvement of the average System Availability towards 95%.
This paper describes how the model is gradually developed and utilized by showing relevant charts, processes and result examples.
Experimental Characterization of Production Behavior Accompanying the Hydrate Reformation in Methane Hydrate Bearing Sediments
Authors: Ahn T. , Park C. , Lee J. , Kang J. M. , Nguyen H. T. 
Published: February 2011

Abstract
The paper analyzed experimentally the production characteristics of hot-brine stimulation accompanying the hydrate reformation in the presence of methane hydrate. Many attempts have been to recover commercially the methane hydrate such as depressurization, thermal stimulation, and inhibitor injection. Hot-brine injection coupling thermal recovery with inhibitor injection has been investigated as one efficient production scheme but the hydrate reformation during the dissociation is problematic, that influences negatively the recovery rate.
An experimental apparatus divided the steel body into 12 blocks not only to describe one-dimensional dissociation effectively but to control the temperature accurately. The specified amount of methane hydrate were formed artificially in unconsolidated and packed sediments where average particle size, absolute permeability, and porosity were 260 μm, 4.4 D, and 42 %, respectively. The production trends were observed in the temperature range, 283.85 ~ 303.15 K and in the injection rate, 10 cc/min and 15 cc/min, respectively. Methane hydrate reformed in all tests, of which reason can be the recombination of water and dissociated methane at downstream zones. In early time, the production rate was low but it increased significantly in late time. The former was why most gas dissociated in upstream were consumed to reform hydrate in downstream while the latter was to combine both dissociation amount of initial and reformed hydrate. The dissociation front moved fast at the higher temperature and injection rate. The production efficiency of 15 cc/min and 294.55 K was similar to that of 10 cc/min and 303.15 K. The results confirmed the production behavior of methane hydrate under the reformation phenomenon and could provide with the fundamentals to develop the efficient production scheme based on hot-brine stimulation.
SMA Technology Extends the Useful Range of Nonceramic Proppants in the Eagle Ford Shale
Authors: Stegent N. A. , Wagner A. L. , Montes M. , Omsberg A. , Riley K. M. 
Published: February 2011

Abstract
The industry has constantly struggled to balance proppant supply with demand. With the increasing levels of propped fracture stimulation activity in horizontal-shale developments in North America, alternative solutions might need to be used if the desired proppant is not available to fit the completion timeframe. Operators must continue to drill and complete wells, and suitable proppant availability is key to the process when propped fractures are required to deliver commercial returns.
Multiple parameters determine proppant-selection criteria for a fracture completion, such as closure stress, Young's modulus (YM), Poisson's ratio (PR), reservoir pressure, hydrocarbon type, etc. As multistage fracturing in horizontal wells increases, the availability of adequate quantities of suitable proppants has become an issue. Deeper, hotter wells with higher closure stresses typically require man-made ceramics to deliver sufficient fracture conductivity under these extreme conditions. An alternative technology was applied in an Eagle Ford shale completion that provided an economic solution when man-made proppants were not available. An on-the-fly Surface Modifying Agent (SMA) was applied to natural quartz sand substrate and pumped under conditions that normally exceed the useful range of this proppant. An engineering methodology was implemented to determine the risks associated with “pushing the envelope” with this technology and assesses the probability of a successful commercial development.
The application of an onsite SMA to proppant during a frac job can provide operators with additional options when the desired proppant is not available. It also allows for varying degrees of flexibility during onsite job redesign and execution. This technology can help keep a completion program on schedule and add additional benefits related to sustained production. The application of an onsite SMA to natural-sand substrates can provide an efficient low-cost alternative to man-made proppant, especially during times of supply shortages.
A Novel Nondamaging Friction Reducer: Development and Successful Slickwater Frac Applications
Authors: Sun Hong , Stevens Dick , Cutler Jennifer , Wood Benjamin , Wheeler Richard 
Published: February 2011

Abstract
Friction reducers are commonly used in slickwater fracturing operations to minimize energy loss due to tremendous amount of friction between tubular goods and water or brine solutions during the pumping of very high rate of fluids. Currently almost all friction reducers used are high molecular weight polyacrylamide emulsions. Large amount of polymers is injected into the formation even at very low concentrations (typically 0.5 – 2 gpt) due to the large volume of a typical slickwater frac treatment. Concerns have persistently been raised over possible fracture and formation damages caused by the friction reducers. All current friction reducers, including copolymers, are polymers with C-C backbones, which are difficult to break. Tests show that these polymers, even in the presence of oxidizer breakers, cause formation damage.
A novel friction reducer featuring easily breakable chemistry has been developed to offer clean, non-damaging slickwater stimulations. This new non-damaging friction reducer, delivered also in liquid form for the ease of transportation and field operation, is very effective as a friction reducer, compatible with common chemical additives (scale inhibitors, biocides, clay stabilizers, surfactants, brines, etc) and stable towards mechanical shearing. This paper will present the product development details and lab tests on the effectiveness of the new friction reducer in water and various brines and its hydration profile at different temperatures, chemical compatibility and breaking profiles. Formation damage studies on tight sandstone and shale formation on this new friction reducer in comparison with the conventional ones have been conducted and will be discussed in the paper. Results show the non-damaging friction reducer degrades easily with conventional breakers and leave no damage to the formation. Several successful multi-stage slickwater frac completions have been performed with the new friction reducer and these field trials will also be reviewed.
Build-to-Suit Technologies For Wellbore Construction In Deepwater And Ultradeepwater Gulf of Mexico
Authors: Ali Tarab H. , Mathur Rohit , Sharma Nitin 
Published: February 2011

Abstract
Recent discoveries in the Gulf of Mexico (GOM) and around the world clearly affirm the fact that the age of cheap oil is close to being over, as we explore reservoirs deeper and in more challenging environments. To keep up with the US and global energy demand, major operators in the Gulf of Mexico are shifting their focus toward deepwater and ultradeepwater operations.
A customized package of solutions and technologies is needed to offset the costs of drilling in deepwater and ultradeepwater environments. This paper discusses the deployment of certain technologies (customized to meet operators’ specific challenges) that helped the operators reach their goals. The paper also examines technologies that are still at the stage of inception but hold tremendous potential for development and execution in ultradeepwater operations.
The following case studies and examples from Miocene and Lower Tertiary plays in the GOM are illustrated in this paper: Real-time drilling dynamics for optimum drilling parameters selectionReal-time density imaging to reduce structural uncertaintyCasing while drilling for trouble zone isolationAzimuthal resistivity for 3D geosteeringHigh-pressure/high-temperature (HP/HT) constant rheology for equivalent circulating density (ECD) and surge reductionDrillpipe valve for dual gradient drilling (future potential)High-speed data telemetry for real-time decisions (future potential)
The future of wellbore construction will depend on build-to-suit technologies encompassing directional drilling, formation evaluation and drilling fluids that can deliver optimized solutions in challenging and costly operations.
Reducing Steam Oil Ratio in Steam-Assisted Gravity Drainage
Authors: Orr B. W. , Srivastava P. , Sadetsky V. , Stefan B. J. 
Published: February 2011

Abstract
North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (&lt;90m) and thus 85% of the oilsands (232 billion bbl recoverable reserves) must be recovered using in-situ techniques. Steam-assisted gravity drainage (SAGD) has become the method of choice for oilsand producers and it is therefore critical to optimize this process. Steam additives can improve recovery from the SAGD process. The additive, hydrocarbon or not, is soluble in bitumen at reservoir conditions and serves to decrease its viscosity, thereby increasing the production rate over a process driven solely by steam.
This paper investigates several steam additive pilot projects with a focus on a project at Long Lake. Also, this paper discusses laboratory experiments involving a comparison of the performance of different hydrocarbon and non-hydrocarbon additives for assisting the SAGD process. Steam additives should be pursued because successful implementation would significantly improve profitability by accelerating production, decreasing water losses and decreasing steam requirements. Additionally this will address environmental concerns by decreasing CO2 emissions associated with steam generation using natural gas. If successful, these steam additives will also increase reserves both per well pair and on a total oilsands basis.