bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure-Activated Sealant Economically Repairs Casing Leaks on Prudhoe Bay Wells
Authors: Chivvis R. W. , Julian J. Y. , Cary D. N. 
Published: March 2009

Abstract
Pressure activated sealant was used to repair casing leaks in two Prudhoe Bay, Alaska oil wells without the use of a rig workover. The significance of the treatments, development of job screening criteria, and job planning and execution are reviewed.
Production casing leaks are a frequent problem in mature oil fields, particularly where there is corrosion. Wells with casing leaks usually do not meet well operating criteria so they must be shut-in, causing a loss in valuable production. Casing leaks normally require a rig workover to repair since the tubing often has to be removed. Rig workovers are very expensive in offshore locations, remote areas, and harsh climates. Special pressure activated sealants, diagnostic tools, and treatment techniques have been developed to find and repair casing leaks without removing the tubing.
Case studies of three Prudhoe Bay production wells describe how pressure activated sealant successfully repaired the small casing leaks in two wells without removing the tubing. The third well was not treated because it did not meet the screening criteria. One case study was unusual because the sealant fixed four deep casing leaks with one treatment.
The case studies show how refinements in diagnostic techniques, candidate screening, and treatment planning and execution have resulted in the successful application of pressure activated sealant to repairing casing leaks in producing wells and in one case repaired four leaks with one treatment. Using pressure activated sealant to repair casing leaks can result in significant cost savings and return wells to production sooner. The treatment can be particularly useful in mature fields with corrosion problems and in offshore, remote, and arctic fields where rig workovers are expensive and rig availability is limited.
Isoconversional Kinetic Analysis of the Combustion of Heavy Hydrocarbons
Authors: Cinar M. , Castanier L. M. , Kovscek A. R. 
Published: March 2009

Abstract
One method to access unconventional, heavy-oil resources is to apply in-situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat to reduce oil viscosity and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. Experimental analysis of crude-oil oxidation kinetics provides parameters, such as activation energy, for modeling and optimization of ISC processes. The complex nature of petroleum as a mixture and multistep character of oxidation reactions complicates substantially the kinetic analysis of crude oil. Isoconversional techniques provide model-free methods for estimating activation energy and naturally deconvolve multi-step reactions. In this sense, they are superior to the conventional methods of analysis of crude oil oxidation kinetics. Isoconversional methods are also useful as a diagnostic tool to recognize the burning characteristics of different oils. Our work shows that different phenomena, such as "cool flames", can be identified by using isoconversional analysis. The combustion kinetics of three oil samples are reported adding to the knowledge base of crude-oil combustion and the applicability of isoconversional analysis to oil oxidation is tested experimentally. In addition synthetic examples are presented to show the diagnostic characteristics of the analysis.
Coiled Tubing and a Fluidic Oscillator Used as an Aid for Selective Placement Technique to Wells in Huila, Colombia
Authors: Pinto Sandra Gonzalez , Callarotti Gian Franco , Tellez Oscar 
Published: March 2009

Abstract
One of the major challenges of stimulating wells in the San Francisco and Balcon fields in Colombia is adequate fluid placement. The wells in these areas have different zones open to production. Typically, these zones show severe petrophysical contrasts regarding permeability, porosity, and oil-and-water saturations. Permeability can be 25 times greater in one zone than another. Furthermore, these open zones may also have different pressures. These variations in rock and fluid properties increase the probabilities for preferential flow to the zones of less resistance. Therefore, selective stimulation techniques are commonly used to treat wells in these two fields. Single and straddle packers for bull-heading and coiled tubing with conventional nozzles are some of the commonly used techniques.
This paper discusses the results from using CT and a fluidic oscillator as a new alternative to place stimulation fluids. A true fluidic oscillator generates pressure waves using the Coanda effect. These low amplitude, high-frequency pressure waves enhance damage removal and fluid placement through cyclic loading. This technique has been extensively used in the San Francisco and Balcon fields for Hocol in Colombia. Three stimulations using CT and a fluidic oscillator are discussed in this paper as well as the results from this fluid placement technique with conventional placements showing how the use of CT and a fluidic oscillator can increase hydrocarbon recovery.
Expandable Tubulars Facilitate Improved Well Stimulation and Well Production
Authors: Durst Doug G. , Ruzic Neven 
Published: March 2009

Abstract
Growing energy demand is leading the industry to re-evaluate resources found in challenging conditions such as unconventional gas formations, re-entry wells, and/or low producing wells. Cost-effective development of these resources depends on strategic application of advancing production solution technologies. To enhance production and improve recovery processes, more efficient perforating and fracturing methods have evolved along with advancements in wellbore production hardware via use of solid expandable tubulars or combinations of solid expandable and conventional tubulars.
Expandable technology applied as a completion/production string facilitates increased fracturing rates, resulting in improved conductivity and enhanced hydrocarbon production. Expandable tubulars can be used in re-entry wells to isolate old perforations, allowing for new zones or new sections within zones to be perforated and stimulated. Either a combination tubular cladding system or a solid expandable system can provide an integral component in new wells or re-entry wells where low-permeability reservoirs, such as those characteristic of unconventional gas formations, require isolation and separation for selective or pinpoint hydraulic fracturing or re-fracturing.
Although successful stimulation is routinely attained from hydraulic fracturing, ancillary downhole tools such as conventional completion equipment often compromise results by restricting flow and affecting pressure performance. Solid expandable systems can optimize the fracturing parameters by maintaining larger diameters and providing seals for selective multi-zone or zonal isolation purposes. These production systems can consist of either solid expandable tubulars or expandable sealing sections combined with conventional tubulars using premium connections, thus providing a superior completion solution.
This paper will explain how solid expandable tubulars can be used to facilitate first-time fracturing, re-fracturing, and multi-zone fracturing, refurbishing older wells, and attaining large-diameter production/reservoir conduits. Integration and system development of this technology will be discussed. Case histories will be cited to illustrate the effectiveness of solid expandable systems in enhanced production and fracturing applications.
Synergies and Opportunities Between EGS Development and Oilfield Drilling Operations and Producers
Authors: Petty Susan , Bour Daniel Lee , Livesay Billy Joe , Baria Roy , Adair Richard 
Published: March 2009

Abstract
We discuss the emerging Engineered Geothermal Systems (EGS) industry, highlight its significant relationship with the oil and gas drilling industry, and describe overlapping opportunities available for the two industries. EGS refers both to the creation of geothermal reservoirs in deep hot rocks and sedimentary basins, as well as to the unconventional use of co-produced hot water from oil and gas production. It has the potential for transforming geothermal energy from a relatively minor source of baseload electricity production into a resource capable of providing 10 percent or more of domestic US energy needs within a few decades. Traditionally, geothermal has been tied to places with the relatively rare combination of plentiful hot water that is shallow. EGS reservoirs exploit the natural increase of temperature with depth nearly everywhere on Earth. The recovery of just 2 percent of the thermal energy between 3 and 10 km depth in the United States represents about 2,800 times the current domestic energy usage. A modest drilling program of 150 wells per year would provide annual increments of 1,000 to 2,000 MWe. EGS power generation is a readily available domestic source of energy that is reliable, steady, and environmentally friendly. Not only does it emit no greenhouse gases, but there is the potential for CO2 sequestration by mining the geothermal heat with CO2, rather than with water. EGS power plants would require minimal footprints, and waste hot-water from the plant can be exploited for direct-use applications such as manufacturing processes and heating buildings and greenhouses. Drilling rigs, casing, tools, and other typical oil field services have been used to drill geothermal wells. This paper will discuss the level of these services needed for EGS growth, and describe new technologies that must be developed, primarily for the creation of EGS reservoirs.
Effects of Water on Kinetics of Wet In-Situ Combustion
Authors: Lapene A. , Castanier L. M. , Debenest G. , Quintard M. , Kamp A. M. , Corre B. 
Published: March 2009

Abstract
Wet combustion tube runs have been performed and are compared to dry ones. In a previous study using ramp temperature oxidation (RTO), we have underlined the effects of water on heavy oil combustion through chemical interactions.
Five combustion tube experiments using heavy oil have been conducted. Two dry runs with different air fluxes and three wet combustion runs with the same air flux but various water air ratio (WAR).
We have tried to link past observations concerning differences between dry and wet combustion, such as changes in oil recovery, observed in our experiments and those which have been underlined in the study of reaction kinetics via RTO.
Polymer Gel Water-Shutoff Applications Combined With Stimulation Increase Oil Production and Life of Wells in the Monterey Formation Offshore California
Authors: Turner B. , Zahner B. 
Published: March 2009

Abstract
Excessive water production from the Monterey Formation of the Sockeye Field offshore Santa Barbara, California led the operator to consider polymer gel water shutoff treatments. Field water rates were approaching the limit of the platform water handling capacity and threatened to curtail future development and/or require a multi-million dollar facility expansion. By utilizing chromium crosslinked polyacrylamide gel technology, the operator significantly reduced the water production. However, after gel treatments were injected and the wells were returned to service, both water and oil production were significantly lower. The operator subsequently stimulated the wells with acid and saw significant increases in oil rates while maintaining a reduction in water production.
The result of combining the water shutoff treatments with the stimulation was a lowered water production rate and increased oil rate that neither technique would have yielded on its own. At this time, four wells have been treated with both gel and acid and one has been treated with gel alone. Of the four treated with gel and acid, three had reduced water rates and three had increased oil rates. Moreover, all gel treatments were pumped down production tubing without the need of a rig, using the vendor's self-contained trailer that included all mixing and pumping equipment. While not specifically designed for offshore use, this equipment greatly simplified logistics and the total cost was low enough that the economics could be based solely on savings in water handling costs.
Establishing Injector/Producer Connectivity Before Breakthrough During Fluid Injection
Authors: Izgec O. , Kabir C. S. 
Published: March 2009

AbstractInterwell connectivity is a key issue in any field development planning, especially when secondary and tertiary recovery methods are contemplated. Stakes are particularly high in deepwater and other costly environments where the well count largely dictates project economics. Traditional approaches to discerning reservoir compartments include fluid PVT properties, geochemical fingerprints, tracer testing, and transient-pressure testing. While fluids may provide clues about reservoir connectivity or lack thereof, they cannot tell us about the degree of connectivity between wells. In contrast, pulse testing may provide the necessary information, but the interwell permeability so estimated is skewed toward the observation well, and therefore may not be entirely satisfactory. This study presents an alternative method for establishing interwell connectivity involving production and injection wells.We show that capacitance-resistive modeling (CRM) is a viable alternative to solving transient-flow problems. Equivalence of streamline simulations and CRM is established for fractional flow directed at each producer. We also showed that one can discern connectivity between the injector and producers in an inverted-five-spot pattern and in channelized reservoirs, with limited injection in prebreakthrough scenarios. In closed systems, even low-signal quality may suffice for characterization, provided reasonable injection perturbation exists. Excessive voidage appears to be a nonissue as far as signal propagation is concerned.
Using PLT Data To Estimate the Size of Natural Fractures
Authors: Hoffman B. Todd , Narr Wayne , Li Liyong 
Published: March 2009

Abstract
In naturally fractured reservoirs, determining fracture properties, such as size and permeability, is difficult due to the limited data about the fractures. The primary information that is available, mainly from image logs or core, is known only at the wellbore; however, the fractures can be local to the wellbore region, or they can extend hundreds of feet from the well. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated. Thus, rates and declines in primary production and breakthrough times of injected fluids can be better estimated, and the field can be developed more efficiently. The goal of our work has been to combine dynamic data with static data to better characterize fracture properties, especially the size of fractures away from the wellbore.
PLT information can be used in conjunction with static data to more accurately define fracture properties such as size and permeability. A single-well single-phase flow-simulation model is constructed with discrete fractures at each location where wellbore inflow is observed with a PLT. A program has been created to automatically perturb the lengths and heights of model fractures until their flow response matches the actual measured response (i.e. history matching PLT data by changing fracture properties). This program is designed for wells that intersect multiple fractures.
The tool has been used on a number of different examples, and matches are achieved in all cases. Fracture lengths range from a few feet to thousands of feet. The optimization is efficient as it generally finds solutions after iterating through only about 20 flow simulations. To demonstrate the various capabilities of the program, different options are used in different cases. One example is matched with six different models to provide a range of uncertainty for the fracture sizes.
Improvements in Capacitance-Resistive Modeling and Optimization of Large Scale Reservoirs
Authors: Weber Daniel , Edgar Thomas F. , Lake Larry W. , Lasdon Leon , Kawas Sami , Sayarpour Morteza 
Published: March 2009

AbstractOil production strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation.A simple capacitance-resistive model that characterizes the connectivity between injection and production wells can determine an injection scheme that maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. Research previously conducted has shown that this simple dynamic model provides an excellent match to historic data. Based on a number of simulated and two actual fields, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated historic decline.An advantage of using a simple model is its ability to describe large scale systems in a straightforward way with computation times that are short to moderate. However, applying the capacitance-resistive model to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories that often represent a variety of different reservoir conditions. New wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, history matching large reservoirs by nonlinear regression is more likely to produce parameters that are statistically insignificant, resulting in a parameter dense model that does not accurately reflect the physical properties of the reservoir. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods.
Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs
Authors: Pan Yan , Kamal Medhat M. , Kikani Jitendra 
Published: March 2009

AbstractAdvanced drilling technology has been widely and successfully applied to construct multilateral wells in reservoirs. This paper presents several field applications of the modeling of complex well architectures. A generalized semi-analytical segmented model, accounting for multilateral well systems in commingled layered reservoirs was used in several field applications. Cases include evaluating the flow efficiency of different configurations of wells with multiple laterals, analyzing an interference test between three horizontal wells in Al Rayyan oil field offshore Qatar, and analyzing a well test in a commingled multilateral well in a multilayer reservoir in the Dos Cuadras field offshore California.The model can predict the production performance under either constant-rate or constant-pressure conditions of a well system with any number of arbitrarily oriented laterals of any length and nonuniform formation damage. The reservoir layers, with different porosities, anisotropic permeabilities and drainage areas, are non-communicating except through the wellbore. The solution is valid for large reservoirs and when no-flow or constant-pressure boundaries affect the pressure behavior.Results of applying this method in the field cases showed that the model enabled us to predict multilateral well performance, to obtain information about reservoir connectivity, and to estimate well and reservoir properties in a multilayer system. Uncertainty, due to the large number of unknown parameters in such a complex system, represents the main challenge in using this method. It is recommended to use other means (e.g. production logging and PNC log) together with pressure transient data to reduce the uncertainty. Whenever possible, each lateral should be tested individually to provide more reliable estimates of reservoir and well properties.The presented model and the lessons learned from the field applications provide engineers a tool to use transient data collected from multilateral wells in multilayer systems for reservoir characterization and performance forecast.
Operational Energy Savings through the use of Continuous Sucker Rods with Progressing-Cavity Pumps
Authors: Hopkins Nicholas L. 
Published: March 2009

Abstract
This work analyzes the difference in energy requirements between using continuous sucker rods and using conventional jointed sucker rods in Oilwell Progressing-Cavity Pumping (PCP) systems, with an emphasis on how each rod type is affected by well depth and fluid content. PCP is a rotational pumping application; these pumps transfer fluids through internal cavities by rotating a rotor inside of a stator. Calculations for this study are performed with a computer spreadsheet to illustrate potential energy savings achieved with continuous rod applications. This work expands on previous research addressing continuous sucker rods by observing how changing viscosity (with increasing well depth) can affect pump operation. The focus is on production in the San Joaquin Valley, which typically has high water-to-oil ratios; the properties of brine water and 14° API crude oil are used in the calculations.
Oilfield operators planning to install PCP systems can use data acquired from this work to estimate the influence of several factors on pump operational energy costs. Results can be iterated from this study to estimate different operating situations depending on the particular well conditions. This study is also an attempt to understand anecdotal evidence found in existing wells with PCP and continuous sucker rods already installed
Using a continuous rod results in operational energy savings over conventional rod strings, the magnitude of which depends on well depth and fluid content. The author concluded that the increased energy savings were a result of omitting couplings and guides from the rod string. Couplings and guides decrease the annulus area for the working fluid to flow through, which increases pump pressure requirements. Greater savings are observed in deeper wells because the rod string is longer, which requires more couplings and guides on a conventional rod string.
Predicting the operational energy cost savings attained by using a continuous rod can help determine whether the capital cost of installing continuous rods will be recouped in a profitable timeframe. Calculated energy savings may also be used towards applying for energy saving incentives through California utilities customer energy efficiency programs, which can help offset the investment in energy-efficient building and design and ultimately lead to a higher return on investment.