bluuebunny/crossref_metadata_2025 huggingface dataset:
Measurement of Recovered Solvent in Solvent Aided Process
Authors: Gupta S. , Gittins S.
Published: February 2011

Solvent Aided Process (SAP) is a solvent based enhancement of SAGD where small amounts of solvent such as light alkanes or natural gas liquids are added to the injected steam to enhance reservoir performance and associated project economics. Expectedly, the economics with SAP are sensitive to the solvent recovered from the reservoir, making its measurement in a field test an important factor.

When a single-component solvent like butane, which is not generally present in the produced heavy oil or bitumen, is used in SAP, estimation of the recovered solvent can be achieved uniquely. But when the solvent also has heavier components, some of which overlap with the lighter components of the produced oil, the measurement is not straightforward. The problem is compounded by the fact that the interaction with reservoir changes composition of the produced solvent and makes it time-varying on account of different resident times associated with different components. The issue is further complicated by the fact that produced oil also undergoes an in situ solvent de-asphalting process (SDA), which is also time and space varying in the reservoir. If there were no in situ SDA, one potential method to measure the amount of produced solvent would be to measure the total asphaltene content as an oil ‘marker’ in the produced blend. Use of a tracer with injected solvent as well as regression based analyses for solvent-fraction (using compositional analyses of solvent, bitumen and the blend) of the produced blend is error-prone for these same reasons.

Due to the issues in the approaches mentioned above, a new method is desirable for a more robust and unique assessment of the solvent amount in the produced fluids. This paper elaborates on the current challenges and proposes a couple of workable methods including use of maltenes-metals content as oil markers as well as the use of boiling point curves of the produced blend compared to that of the base oil.

Such techniques of estimating the recovered solvent can facilitate a more objective assessment of SAP field tests and enable economic evaluation of its application to a commercial scale.
Partial Upgrading of Bitumen at SAGD Wellsite
Authors: Fukuyama H. , Nakamura T. , Ikeda A.
Published: February 2011

The high-conversion soaker cracking (HSC) process, an advanced continuous thermal cracking, has been used commercially for more than 20 years at a refinery converting heavy oil to valuable lighter distillates. The residue from the process is the heaviest liquid fuel in the world and is used for a boiler at the refinery. The application of HSC was studied as a partial upgrader at a SAGD wellsite to improve the transportability of bitumen using thermal cracking for the reduction of diluent volume and replacement of natural gas with the cracked residue from the HSC process for steam generation at the boiler. The advantage of HSC was examined by conducting thermal cracking tests using Athabasca bitumen. Material balances of the integrated SAGD and HSC for different SORs were calculated to obtain blended oils with API 21 for pipeline transportation. The calculated values were compared with the material balance of the standalone SAGD, based on the results of the test. The economic study of SAGD/HSC integrated process compared with the standalone SAGD showed that the IRR of the integrated SAGD/HSC was less volatile to the WTI and the natural gas market price. The economic benefit of partial upgrading of bitumen at the wellsite was more pronounced for higher prices of WTI and natural gas.
Advantages of Managed Pressure Drilling and the Recent Deployment of the Technology in Vietnam
Authors: Nas Steve , Gedge Ben , Palao Felbert , Viet Bot Nguyen
Published: February 2011

Managed Pressure Drilling (MPD) is a technology that accurately controls the annular pressure while drilling and completing wells. The intention of MPD is to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be controlled and circulated out and an overbalanced condition will be restored.

MPD can be used to reduce well construction times, which in today’s high cost rig market is appealing to any exploration, appraisal or field development team. The MPD technology can, to a certain degree reduce drilling fluid related formation impairment, and can through the reduction of the mud weight reduce the cost of mud losses as well as the related non productive time that is spend in curing losses.

MPD technology is now deployed extensively in the Asia-Pacific Region by many operators, to alleviate a range of pressure related drilling problems. The main applications for MPD include pressurized mud cap to deal with the kick/loss situations in fractured carbonates as well as constant bottom hole pressure systems in wells with narrow pore pressure fracture pressure windows or in depleted reservoirs.

This paper is intended to enhance the understanding of the value delivered through the use of MPD techniques, together with recommended equipment designs for each application. Some case studies will be used to quantify value delivery for a range of equipment designs and to better define the operational issues associated with MPD operations.
Wireline Well Tractor Technology Experience in Extended Reach Horizontal Well
Authors: Shawly Alaa S. , Buali Muhammad H. , Omran Mohammed R. , Dashash Alaa A. , Guraini Walid K. , Nawawi Ahmad A. , Al-Khamees Haider , Awami Nassar Al , Torne Juan
Published: February 2011

Horizontal wells with extended reach drilled in Ghawar field awarded significant improvements, maximizing hydrocarbon production and attained ultimate recoveries. Over the life of those wells, intervention work is necessary to maintain hydrocarbon production by conducting remedial action, such as acid stimulation or water shut off. Necessary data for decision making can be obtained through running surveillance tools, which has proved to be a challenge, considering that these sensors will have to be deployed to total depth (TD). Many well intervention methods have been developed over time to overcome these challenges, such as coiled tubing (CT) and several types of wireline tractors.

Wireline tractor technology has evolved to reduce time, cost and improve data quality and increase wellbore coverage. The use of a wireline tractor imposes fewer personnel on the job, much less equipment and less lifting of heavy loads resulting in a smaller footprint impacting the environment. In addition, the fast rig up of the wireline tractor and the running in hole (RIH) and pulling out of hole (POOH) speeds the highly deviated section, and cuts down on operating time.

This paper will demonstrate horizontal logging experience gained from trial testing a new deployment solution for the production logging tool (PLT). A new generation of wireline tractors was utilized successfully to deploy the PLT for the first time in the Saudi Arabian field and showed exceptional performance. The tractor proved its capability to overcome different challenging wellbore conditions, such as rugosity, washouts, and high dogleg severity (DLS). Moreover, the tractor was able to efficiently pass through very short sections with large changes in the inclination and azimuth,

This paper also covers the whole cycle of candidate selection, job design, execution challenges, post job evaluation, lessons learned and experience gained to optimize similar future jobs.
How to Achieve and Control Branch Fracturing for Unconventional Reservoirs: Two Novel Multistage-Stimulation Processes
Authors: Stanojcic M. , Rispler K.
Published: February 2011

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

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

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 <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

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

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

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

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

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

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

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

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

North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (<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.
Natural Gas: The Green Fuel of the Future
Authors: Taylor R. S. , Tertzakian P. , Wall T. , Wilkinson J. , Graham M. , Young P. J. , Harbinson S. W.
Published: February 2011

As populations and economies continue to grow globally, energy demand will grow proportionally. Extensive work by Peter Tertzakian (2006, 2009) has shown crude oil supplies may not keep pace with this increased demand. The shortfall must be met by other energy sources.

Only two current energy sources have the global capacity to, by themselves, address increased energy demand in a timely manner. These are natural gas and coal.

Traditionally, the major use of crude oil has been for processing into transportation fuels, with lesser amounts being used for petro-chemicals and home heating. Natural gas and coal have been used primarily for electrical generation and heating.

A pivotal transition will likely occur in which natural gas and coal begin to see increased use as transportation fuels. A battle for market share between primary fuels will likely ensue.

The objective of this paper is to present data comparing the environmental impact of using methane vs. coal. A compelling case for the use of natural gas as the future "green fuel" emerges.
Safety Valve for Ultradeepwater Applications
Authors: Sloan Jim , Darren Bane
Published: February 2011

In recent years, offshore oil and gas exploration has continued to push into deeper and deeper waters, such as those in the Lower Tertiary fields of the Gulf of Mexico. As these field discoveries are being completed, the application requirements for safety valve installations are moving toward valves that can be set very deep, but still only require a relatively low operating pressure to control the valve. In traditional safety valve applications, operating pressures are sensitive to the wellbore pressure and are typically above those pressures to hold the valve in the open position. As the setting depth of these valves goes deeper, the operating pressures increase to a significant level such that umbilical and wellhead design and performance is detrimentally affected.

As a result of these constraints that occur in deep, offshore fields, a safety valve solution is desired to provide an ability to minimize opening pressures by balancing tubing pressure in high-pressure/high-temperature (HP/HT) conditions, yet allow extreme valve setting depth capability without compromising operational characteristics such as high opening pressures or pressure-balanced pistons using long-term valve gas charge storage.

This paper discusses a new surface-controlled, subsurface safety valve (SCSSV) that uses the low opening pressures of a tubing-pressure-insensitive safety valve, without gas-charged assisted closure or dual control lines for balanced line applications. This system enhances valve reliability by eliminating the need for pressure reversals across the valve’s critical actuating piston seals while maintaining tubing pressure insensitivity. This system provides for much deeper valve depth capabilities compared to the methods previously discussed and also allows the safety valve to account for annulus pressure buildup scenarios not possible in current SCSSV applications.

This paper presents design and development considerations for a new SCSSV solution allowing ultradeep setting depths without closed volume gas charged spring techniques utilized in current deep-set SCSSV technology. Test results will demonstrate the features, benefits, and reliability of this new safety valve in reference to previously unattainable valve operating depths in aggressive subsea well designs or annulus pressure buildup scenarios.
An Overview of Horizontal Well Completions in the Haynesville Shale
Authors: Thompson J. W. , Fan L. , Grant D. , Martin R. B. , Kanneganti K. T. , Lindsay G. J.
Published: February 2011

A steep learning curve has evolved in drilling and completing horizontal wells in the Haynesville shale. The challenge is to understand the production mechanism of the Haynesville and how completion practices in relation to lateral lengths, stages, and stimulation treatments relate with production.

This paper gives an overview of the Haynesville horizontal well production, the dominant factors which effect production, and a detailed analysis of the completions. Dominant factors which effect production in the Haynesville shale can be broken into four categories: geology/petrophysics/geomechanics, landing and placement of the lateral, completions, and production control. Integrating all four categories together is critical to characterize well performance and optimize future production; however, this paper focuses primarily on the completions.

Self-organizing maps (SOMs) of 49 wells in the Strait area of the Haynesville shale reveal that high producing wells have been treated primarily with slickwater, high fluid and proppant volumes, moderate amounts of 100-mesh sand, and moderate pump rates per perforation. These wells are typically located in cluster spacing of about 75 ft and have stage lengths of about 300 ft. Most show lower post-fracture instantaneous shut-in pressure (ISIP) than lower-producing wells. These observations and characteristics of high producing wells along with best completion practices can help design optimal completions and stimulation treatments in the Haynesville.
Latest Technological Advances in Rod Pumping Allow Achieving Efficiencies Higher than with ESP Systems
Authors: Takacs Gabor , Belhaj Hadi
Published: February 2011

Two of the most important artificial lift methods applied in oil wells are sucker-rod pumping and electrical submersible pumping with thousands of installations all over the world. Their operational features and application ranges are quite different but in many cases any of them can be used in a given well. The final selection of the proper method has to be based on their energy efficiency and the one requiring the least amount of surface power input is selected. This paper provides the necessary background for evaluating the effectiveness of the two lift methods investigated and for pinpointing the requirements of achieving maximum power efficiency of artificial lifting.

The power flow in the pumping system is investigated and the sources of power losses along with their usual ranges are described. The overall power efficiency of the system is defined by a simple formula that provides the necessary insight into the main components of the power losses occurring in different system elements. A thorough investigation of the efficiency components allows one to find the factors that most markedly influence the total system’s power requirement. As shown in the paper, the most important requisite of achieving maximum effectiveness is the proper choice of the pumping mode, i.e. the combination of plunger size, stroke length, and pumping speed.

The calculation of energy losses in the components of the ESP system is detailed and the relative importance of the individual losses is shown. Since the components of the ESP system are connected in series, a relatively simple formula can be used to describe the effect of electrical and hydraulic losses on the efficiency of the total system. The terms of the final formula were investigated for their importance and for their contribution to the overall effectiveness of the ESP system. Results of this investigation provide crucial information on how to design an ESP system to provide the highest power efficiency.

The practical use of the proposed calculation models is illustrated by presenting an example case where a relatively high liquid rate (1,300 bpd) from the same well is produced by rod pumping and ESP. Detailed installation designs resulted in several different operation modes for both sucker-rod pumping and ESP. The paper proves that using the latest technologies like high-strength sucker-rod connections, sucker-rod pumping can successfully compete with ESP installations by attaining higher energy efficiencies.
Carbon Sequestration From Waste via Conversion to Charcoal: Equipment for a Small Scale Operation
Authors: Gupta S. C. , Struyk A. , Gilbert D.
Published: February 2011

Carbon emitted on account of our continued use of fossil fuel can be offset using carbon capture and storage (CCS). The technology for this exists, however the economics of it is context dependent and CCS is shown not to be very cost effective in oilsands. Committing to the needed large scale sequestration projects without properly considering alternatives can prove costly at both economic and social levels. Charcoal sequestration, discussed earlier by Gupta carries with it a few advantages such as being less costly and lacking any post operation liabilities. Above all, it is reversible allowing flexibility of policy and operation and avoiding long term or large scale commitments.

The economics of the charcoal approach depends mainly on two factors: the cost of the feed biomass and the cost of processing. The first of these is addressed by using municipal waste as feedstock which can be available free of charge. Expectedly the cost of processing, the second factor, depends on the apparatus and the scale of operation.

In this paper, the authors discuss prominent traditional and modern apparatus used for conversion of biomass to charcoal with their benefits and drawbacks and describe a simple and pragmatic apparatus which could be assembled relatively easily, for a small scale operation such as processing industrial camp generated solid organic waste.

Offsetting carbon in this manner can obviously be a good way to initiate demo projects for the charcoal sequestration approach as it also helps with waste management. These demo projects in turn will help evaluate various aspects of this novel method of sequestration, and enhance public awareness on the subject which in turn will help the larger society make an informed choice to embark on a right course of action for atmospheric carbon abatement. Additionally, in light of the growing per capita waste worldwide, use of municipal waste as feedstock for charcoal sequestration can be a significant measure of carbon offset at global scale in its own right.
Proactive Maintenance Plans for RTUs of Transmission Pipelines
Authors: Tarabzouni Thamer , Al-Harbi Lafi , Al-Mejna Abdulaziz , Puthukattu Nazir
Published: February 2011

Remote Terminal Units (RTU)s are field devices that are used to remotely control various assets like valves during normal operations and emergency situations. RTUs obtain real-time operational data for field assets and send them to designated SCADA systems. The status of RTU communication links must be monitored closely to ensure continuous operation of equipment and live data flow. To ensure effective operation of these units, inspectors perform regular visits to the scattered RTU sites to check their operating conditions and ensure that they are providing the correct data in a timely manner. This incurs travel costs and poses safety hazards while also planning these trips were difficult given the large operational area of Saudi Aramco.

Therefore, an IT solution was developed to pinpoint and remotely monitor the status of these RTUs in a web-based Geographic Information System (GIS). Also, e-mail and SMS messages are now generated to alert concerned staff about any unit failures even outside normal working hours. Moreover, a GPS-based AVL (Automated Vehicle Location) application was integrated with this solution to enable a faster response to these RTU failures by determining the nearest field maintenance or inspection crews. This integrated solution helps to provide a real time status of all field installed RTUs, optimize the field inspection and maintenance trips, thereby reducing costs and maximizing unit reliability.
Electromagnetic Methods to Monitor Gas Hydrate Distribution and Production in Layered Sediments
Authors: Enkin R. J. , Hamilton T. S. , Wright J. F. , Kilduff M. , Bild-Enkin D. J.
Published: February 2011

Natural gas hydrate reservoirs are hosted in heterogeneous sediments having variable pore fluid salinity. Questions concerning GH formation, detection and production are being addressed and measured in real time with simple laboratory apparatus. Our vessel is pressurized with methane and monitored with individually calibrated pressure transducers and thermistors. The silt or sand pack is assembled using uniform grain size layers containing ~20% by weight of pore fluids. This results in mixed wettability, with pendant water and initial partial gas saturation. Sand packs consisting of silica silts, sands, and charcoal were selected to emulate the dominant lithofacies observed in the Mallik gas hydrate reservoir. Fluids range from distilled-water to 37ppt salinity. A central needle probe permits the measurements of electromagnetic signals across the specimen. Formation of GH alters the bulk dielectric constant of the mixture, through the conversion of water to gas hydrate crystals and or ice. The infilling of primary porosity by gas hydrate or water ice tends to reduce permeability and increase electrical resistivity, while the expulsion of solutes by hydrate or ice formation decreases resistivity by building a salt bridge along alternate permeability paths. Four methods monitored GH formation and dissociation: 1) Deposition or evolution of gas derived from measurement of the ambient pressure and temperature; 2) Calorimetric measurements of latent heat production by exothermic crystallization and consumption by endothermic dissociation; 3) Time-Domain Reflectometry (TDR) measurement of the velocity of electromagnetic signal propagation and reflections at boundaries in the sand pack; 4) Electrical Impedance Spectroscopy (EIS), a frequency domain method permitting direct measurement of the resistance and capacitance spectra. Improvements in real time digital monitoring and data analysis have made possible the recognition of TDR reflections previously considered unattainable in the presence of conducting fluids. The independent monitoring methods, with their various temporal and spatial sensitivities, capture the intricate details of GH formation and dissociation as a time series. In more porous and permeable beds, GH formation as evidenced by a coherent pressure drop and thermal pulse precedes the increase in electrical conductivity and dielectric constant. These results are interpreted to be the result of a diffusive pulse of solute exclusion from the GH-bearing layer into neighbouring sediment. Measurable EM effects suggest that borehole EIS, with lower frequency and greater penetration than TDR, may be effective for monitoring the variable position of GH-Methane interfaces during GH production tests.
Optimized Steam and Condensate Systems in Refineries: How to Improve Operational Reliability / Safety and to Decrease Energy/Water Consumption and CO2 Emissions
Authors: Ivanov Rossen
Published: February 2011

An optimal management of the steam and condensate system in refineries and petrochemical plants has a direct impact not only on safety, but also on the operating costs of the plant. The production down-time due to failures of the steam system is probably the main cost-driver in this analysis. The abnormal failure of equipments and the resulting maintenance costs could also have an important financial impact. Even if the decrease of these costs is difficult to predict in advance, different case studies show the important damages and their financial impact once the failure has occurred.

The decrease of the energy and water consumptions and the related CO2 emissions is easier to establish. Based on the auditing work done in refineries and petrochemical plants, it appears that more than 5% of the yearly steam cost and related CO2 emissions could be saved by optimizing the efficiency of the steam and condensate system. The increase of the condensate return rate could allow saving up to 50% of the quantity of boiler feed-water used prior to the optimization. Higher rate of condensate returning to the boiler means also less water poored on the ground or in the sewer, which also has an environmental impact.

For an average-size refinery with a capacity of 150 000 barrels/day, the total saved costs represent typically several million dollars per year.