bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Breakthrough Technology for Maximizing Water Injectivity and Asset Integrity
Authors: Horsup David I. 
Published: December 2007

ABSTRACT
The importance of maintaining oil production has never been more critical than it is today. For many fields utilizing water injection to maintain reservoir pressure, the injection rate can decline over time due to the blocking of pore throats in the near well bore region. Remediation can be expensive, incur lost production and expose operations personnel to hazardous chemicals. Additionally, the material which blocks the pore throats, also deposits within the injection infrastructure resulting in significant asset integrity challenges. This paper describes a new technology that has been developed that can significantly increase water injectivity, potentially prevent well interventions, maximize production and preserve the integrity of the injection infrastructure.
Through extensive research, a new, patented multifunctional product has been developed that, when injected into the water injection system, cleans away deposits, prevents new deposits from forming and provides corrosion inhibition to the injection infrastructure. This paper discusses the fundamental research that was performed to develop this new technology, and the results of several field applications.
Upgrading Heavy and Extraheavy Crude Oil with Ionic Liquid
Authors: Nares H. R. , Schacht-Hernández P. , Ramírez-Garnica M. A. , Cabrera-Reyes M. C. 
Published: December 2007

Abstract
In this paper the effects of some ionic liquids elaborated with iron and molybdenum used to upgrade the properties of a heavy crude oil are discussed. The underlying objective is to increase the mobility of the oil in the reservoir reducing viscosity and improving the oil quality (e.g. diminishing the asphaltene and sulfur contents and increasing its °API gravity), using ionic liquids based on iron (10 wt%) and molybdenum (2 wt%) compounds, in a liquid phase homogeneously mixed with heavy crude oil in a batch reactor of 500 ml, at 673 K during 4 hours. The API gravity of a offshore heavy crude oil from the Gulf of Mexico increased from 12.5 until 20, kinematics viscosity decreased from 15,416 to 136.63 cSt at 288.75 K, asphaltene content was reduced from 28.65 to 10.82 wt%, while the sulfur was removed from 5.14 to 2.16%; and the distillation obtained by Simulated Distillation was increased from 48 to 71.2 vol%.
Content of aromatics and saturated compounds were increased through the conversion of asphaltenes and resins, which contents decreased from 16.81 to 13.8 wt% and from 28.85 to 10.82 wt% respectively. Finally, the content of total nitrogen was reduced from 780 to 633 ppm in weight which represents a reduction approximately of 20 wt%.
In this work upgrading of a heavy crude oil was obtained through the application of the thermal and catalytic hydrocracking with an ionic liquid. This ionic liquid could be applied into the reservoir combined with in-situ combustion process using unconventional wells in order to improve the recovery of heavy crude oil, producing an oil improved in-situ with lower viscosity, being easier their exploitation, increasing the productivity index in wells, and saving costs of transportation and refining at surface.
Gravity Drainage and Oil Reinfiltration Modeling in Naturally Fractured Reservoir Simulation
Authors: Ladron de Guevara Torres J. Ernesto , Rodriguez-de la Garza Fernando , Galindo-Nava Agustin 
Published: December 2007

Abstract
The gravity drainage and oil reinfiltration phenomena that occur in the gas cap zone of naturally fractured reservoirs are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results.
Gravity drainage and oil reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudo functions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in fractured reservoir simulation.
The modified dual-porosity equations were implemented in SIMPUMA-FRAC,1,18 and solutions were verified, with good results, against those obtained from the equivalent single porosity refined grid simulations. Same simulations, considering gravity drainage and oil reinfiltration phenomena, were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC.
Flooding by High-Concentration Polymer Doubled Oil Recovery of Common Polymer on Field Test with 20% Closed to the Result of Laboratory Test in Daqing
Authors: Liu Bing , Sun Xiuzhi , Wang Kun , Xu Hong , Liu Qi , Liu Xin , Song Shuling 
Published: December 2007

Abstract
Common polymer flooding on-site tests and industrialized application indicates that conventional polymer flooding gives about a 10% more oil recovery than waterflood, with an ultimate recovery of 51% OOIP. But, because the existence of high permeable zones, this sometimes makes polymer flooding insufficient or ineffective in the reservoir. In some polymer flooding producers, after polymer is breakthrough, water-cut increases rapidly, it adversely affects polymer flooding, resulting in on-site enhancing recovery greatly lower than 20% of laboratory estimates.
In 2002, on the basis of high concentration polymerflooding study in lab, we perform high concentration polymer flooding on-site. By optimizing slug combination and adequate monitoring and analyses, water-cut is greatly decreased, with a decrease percentage of 14.5, this improves polymer flooding development effect. The field test data shows, that high concentration polymer flooding in beginning, recovery has given 4.2% higher than that of conventional polymer flooding by Dec. 2005; and flooded in later stage recovers 3% more oil than conventional method, this indicate that the result of high concentration polymer flooding in initial stages is better than in later stage.
Polymer flooding monitoring and simulation technology predicts that 19.8% more oil can be recovered than water flooding, with a production degree of 61% OOIP. On-site high concentration polymer flooding recovery is two times of the conventional polymer.
New Innovative Wireline Jar Adds Significant Value by Reducing Fishing Cost
Authors: Evans Robert W. , Brame James Chester , Rose Lawrence C. , Dorffer Daniel 
Published: December 2007

Abstract
This paper discusses a new, innovative tool, namely a hydraulic jar with a mechanical lock developed to run on wireline cable. The discussion addresses (1) the role and value of wireline jars in electric line operations, (2) technical features of the new wireline jar system with comments on its operation, and (3) a brief review of several of the many successful field applications.
Getting stuck during a logging operation can add significant cost to a well. The new wireline jar has proven to be remarkably effective in freeing stuck wireline tools and preventing costly fishing operations. Freeing the tools also provides the opportunity to complete the required data acquisition as the instruments have historically not been damaged by jarring. In addition, the use of the wireline jarring method described in this paper allows operators to run relatively inexpensive free-fall wireline tools in areas that previously ― due to sticking problems ― have gone straight to drill-pipe-conveyed operations or logging while drilling (LWD) methods.
A multi-conductor jar, called the LockJar®, has been in use for more than four years. The jarring system utilizes a proprietary-design LockJar and Enhancer, both of which remain passive until such time as they are needed. The LockJar can be pulled, without triggering, as hard as desired for durations shorter than the tool's time delay. Slacking off the string resets the LockJar so that it can be pulled again. Experience with this new technology has also led to discovery of valuable best practices for handling stuck tools, which has increased the number of freed tool strings. Among these best practices is the use of properly placed standoffs, particularly in inclined sections of wellbores.
Experience with this new technology began in the GOM but the technology has quickly spread around the world to locations that experience problems with sticking during logging. In the GOM, several examples can be cited including a job where the LockJar was activated over 20 times in six different intervals; and still the well was successfully logged. This well was the very first in the field that was logged without a fishing job.
Successes described in this paper include an example from the US Rockies and in Brazil and other international locations, such as West Africa, where the LockJar also freed tools on their very first run.
Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water Turbidite Reservoirs
Authors: Altman Raphael , Ferraris Paolo , Filardi Fabricio 
Published: December 2007

Abstract
This account describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool, a latest-generation LWD (Logging While Drilling) measurement, was the technology differentiator for optimizing well placement in a number of deep water horizontal wells.
The new directional measurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while drilling horizontal wells, maximizing well position in the reservoir. This paper shows how thin oil rims, faulted reservoirs and those with highly variable structure were able to be developed more efficiently. By reducing uncertainties about the reservoir, the new technology helped optimize production, eliminate sidetracks and minimize well construction cost and risk.
One of the main challenges of maintaining a horizontal wellbore inside a thin hydrocarbon bed is the uncertainty of formation dip. Inside a hydrocarbon bed, real time resistivity images often yield dips that are more representative of stratigraphic features rather than structure defining reservoir boundaries (from surrounding, conductive shale beds). The deep-reading azimuthal electromagnetic measurement helped in early detection of neighboring conductive beds, and the distance to these beds. This ensured that the wellbore was drilled parallel to the structure and inside the ‘sweet spot’ away from non-productive layers.
As reservoirs become more challenging to develop, the use of advanced technology often helps minimize risk. When fields are developed with horizontal wells, it is desirable to maximize well position inside the reservoir layer since the rate of increase in hydrocarbon production increases as horizontal length in the reservoir increases. We show an example of how advanced well placement technology was successful in doubling hydrocarbon production rate compared with wells in the same field drilled with conventional technology.
Use of Conductivity-Enhancement Material To Sustain Productivity in Hydraulic Fractured Wells: Northern Mexico Cases
Authors: Soriano Duverney J. Eduardo , Garcia Raul , Rivera Juan Galvan , Carrillo Alejandro Barrera 
Published: December 2007

AbstractRapid production decline rate is associated with the loss of fracture conductivity after hydraulic fracture stimulation. This loss of conductivity has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Surface modification agents were introduced in the stimulation market around 1997, and according to literature published since then, these materials have been helping to sustain fracture conductivity, and subsequently, mitigating production decline rates.This paper presents long-term results from the use of these materials in hydraulic fracture stimulation operations in the Burgos Basin in northern Mexico; results from offset wells are also presented for correlation and comparison. Production from this basin comes from low-permeability sandstones normally considered tight gas formations.
Impacts From Fractures on Oil-Recovery Mechanisms in Carbonate Rocks at Oil-Wet and Water-Wet Conditions—Visualizing Fluid Flow Across Fractures With MRI
Authors: Fernø M. A. , Ersland G. , Haugen Å. , Johannesen E. , Graue A. , Stevens J. , Howard J. 
Published: December 2007

Abstract
The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions.
Mobile Support Center Provides Cost-Effective Alternative to Dedicated Facility
Authors: Clyde Robert , Akinniranye Goke , Goobie Roger , Alvarez Carmen Elena , Gorgone Ignacio 
Published: December 2007

Abstract
Drilling operators worldwide face increasingly complex and costly drilling challenges. In addition to difficult and sometimes harsh downhole environments, the driller is also faced with a dramatic increase in the quantity and quality of information available to optimize recovery. In many of these situations, there is little or no room for error and the cost of nonproductive time (NPT) due to a poor or less informed decision can significantly increase the final cost per barrel to the consumer.
Advances in cost-effective satellite communication and the application of compression technology have removed the bandwidth limitation, and Internet transfer of continuous high-volume real-time data between the offshore installation and shore-based operations is almost seamless.
With the current shortage of skilled personnel, most major oil and gas companies are exploring remote Operation Support Centers to support their real-time E&P business processes. With a combination of infrastructure, technology, services and processes, these support centers are consolidating their expertise in a collaborative environment so that informed real-time decisions can be made to improve drilling processes and reduce costs.
The economic justification to management and partners for investing and building support centers is clear, but it is necessary to scale the effort and capital expenditure for support centers to each specific drilling operation. This paper describes the concept of low-cost remote support centers that have been used successfully in the Gulf of Mexico, and land drilling projects on the Alaska North Slope and in northern Mexico.
A successful support center must quickly turn real-time data into useful information displayed with minimum latency in a format benefiting decision makers. This depends on the skill and experience of each participating engineer and the quality of the software answer products in this surveillance environment. This paper describes advanced real-time software answer products that take raw drilling data and filter it into different rig states, automatically generating logical outputs.
High-Strength Threaded and Coupled Connectors for Dynamic Riser Applications
Authors: Shilling R. , Payne M. L. , Massaglia J. , Sches C. , Leyer J. , Pinto J. 
Published: December 2007

Abstract
In the last 5 years, a number of key advances have been made with threaded and coupled (T&C) risers. These advances together with high strength steels have enabled these products to reach parity with the current standard of weld-on connectors. The T&C riser concept demonstrates the same reliability, field proven history and high fatigue performance. This concept of connectors and engineered materials up to 125ksi, allow for significant weight savings on the riser system and platform construction. To meet the Global Energy needs now, the industry must move to deeper water and higher fatigue. Thus a new generation of connectors, fully optimized for fatigue, has been designed for inner and outer production riser applications.
These connections reach best-in-class fatigue performance and include innovative fatigue compliant sealing systems. The large number of full scale fatigue test results increases confidence to such a level that fatigue trends and influencing parameters now help to refine the qualification programs. This new standard will also allow the industry to look for new generations of heavy wall riser connectors for xHPHT, flow line, and SCR applications.
The purpose of this paper is to highlight the knowledge that has been accumulated in various fatigue enhancement techniques and the continuous improvement of analysis capabilities.
Pressure Losses of Non-Newtonian Fluids in Drilling Operations
Authors: Demirdal Barkim , Cunha J. C. 
Published: December 2007

Abstract
Precise estimation of annular pressure losses is essential in drilling and well completion operations to control formation pressures and optimize drilling and completion fluids' hydraulic programs. Without accurate estimation of annular pressure losses it is possible to face serious problems that would yield interruption in drilling operation and sometimes lead to abandonment of the well. While annular pressure loss estimations are critical, determination of pressure losses associated with flow of Non-Newtonian fluids is challenging. Many investigators proposed different equivalent diameter concepts to provide a similarity between pipe and annular flow.
In this study we have investigated the coupling effects of rheological model and equivalent diameter definition on pressure losses using three rheological models (Bingham Plastic, Power Law and Yield Power Law) together with four different equivalent diameter definitions. Effects of inner/outer radius ratios and flow rate on pressure losses determined using different rheological model and equivalent diameter pairs are analyzed using an onshore well and an offshore well. The differences in pressure losses using different pairs for the cases of onshore and offshore wells are shown. The study provides detailed analysis on how severely the annular pressure losses varies once rheological model and equivalent diameter definitions are changed for different operating conditions.
An Efficient Horizontal Openhole Multistage Fracturing and Completion System
Authors: Seale R. 
Published: December 2007

Abstract
Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling technologies have pioneered these advancements, with current technology capable of drilling thousands of feet through a thinly bedded hydrocarbon reservoir. Completion advancements designed for extended horizontal wellbores have also advanced, albeit at a slower pace. Initially horizontal drilling was limited to naturally fractured reservoirs with simple open hole or slotted liner completions. This was due primarily to the ability of the reservoir to flow economically without the need for stimulation. Reservoirs requiring stimulation were initially not candidates for horizontal drilling. Developments in completion technology specific for horizontal wells have broadened the reservoirs where horizontal wells can be effectively stimulated.
When drilling a horizontal well, there are two completion options. First, the horizontal can be completed open hole, or with slotted/perforated liner. Effective stimulation along the horizontal wellbore is impossible. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig up and down of the stimulation equipment are required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.
This paper will discuss a new open hole completion system run as part of the production liner, does not require cementing and provides mechanical diversion at specified intervals, thus allowing fracturing and stimulations to be effectively pumped to their targeted zone. Details of the engineering design and testing will be specified, with elaboration on the applications and case histories were these systems have been successfully deployed. The case histories will detail the operational efficiencies of the system in conjunction with the enhanced production realized.
Analysis of Capillary, Gravity and Viscous Forces Effects in Oil/Water Displacement
Authors: Rosado-Vázquez Francisco J. , Rangel-German Edgar R. , Rodríguez-de la Garza Fernando 
Published: December 2007

Abstract
Reservoir performance during waterflooding is important to reservoir engineers. Analytical and semi-analytical flow models with different assumptions have been presented and used widely to describe the flow dynamics of such a process. Most assume that one of the terms, typically capillary forces, can be neglected or considered constant diffusion coefficients, so the simplified diffusive-convective type of flow equations can be solved analytically or by numerical methods. Obtaining analytical or semi-analytical solutions to non-linear diffusive-convective flow equations, including capillary, gravity and viscous forces simultaneously, has been a challenge.
This paper presents a theoretical study of the effects that controlling flow parameters have on saturation profiles and breakthrough time during oil recovery by waterflooding. A mathematical non-linear diffusive-convective type model for immiscible oil-water displacement in one-dimensional vertical homogeneous porous media considering the three chief forces (capillary, gravity and viscous) is derived and solved numerically by using a finite-difference formulation with fully implicit scheme in time and central differences in space.
Dimensionless equations are written so that any of the three forces can be investigated independently; capillary and gravity forces can be "turned on or off." The effects of varying fluid viscosity, injection flow rate, system length or wettability, for both displacing and displaced fluids, can be understood thoroughly. The flow model is versatile enough that it allows for variations of the shape of the relative permeability and capillary pressure functions. The impact of these functions in the driving forces and on oil recovery is analyzed.
The contribution of each of the forces to the dimensionless water velocity and its impact on oil recovery was studied in four flow cases: viscous, viscous-gravity, viscous-capillary and viscous-gravity-capillary; all possible flow cases in water injection problems were considered. Graphical results are discussed.