bluuebunny/crossref_metadata_2025_split huggingface dataset:
Completion Robustness as a Production Management Tool: Case History in a Mature Offshore Field
Authors: Rodrigues V. F. , Catarina A. , Medeiros R. , Quitar L. D. , Chilelli C. F. 
Published: May 2009

Abstract
There is an ever present demand for increasing or maintaining the oil and gas production, on a production unit basis. Thus, it is very important to have a method to define the maximum safe production rate from the completion point of view. In recent years some oil companies introduced sophisticated integrated asset models for production optimization which include well quality assessment and surveillance. This approach allows a quasi-real time production optimization.
This paper introduces the concept of completion robustness, related to the maximum safe production rate, and applies it in a low level of well surveillance floating production unit. Some relevant aspects of the production unit regarding the wells are: subsea completions, a broad range of sand exclusion systems, and most of the wells are on stream for seven years. The paper presents the completion robustness concept, the general method to apply it, and the procedures developed for the specific case study, in which the connectivity between the formation and the well through the sand exclusion system plays an important role.
The main product attained is a list ranking the wells in terms of completion robustness. Based on this list the asset team can decide which wells may support a production increase, which wells must be kept in the current status, and which wells need an intervention or a rate reduction. The main conclusions achieved are: the completion robustness concept is a rational approach to define maximum safe production rate per well from the completion point of view; the method and procedures developed, although suitable for production units with high level of reservoir and well key parameters surveillance, can also be applied to low level of surveillance ones; the use of the completion robustness by the production operations teams have the potential to increase the production output and the wells longevity.
Unique Bi-Center Technology Delivers in Demanding Directional Applications
Authors: Barton S. , Garcia A. , Luther C. , Rodriguez L. A. , Castillo R. , Perez L. 
Published: May 2009

Abstract
Hole-opening on directional motor assemblies has always been problematic. This is due to the fact that mainstream string hole opening tools cannot be used due to lack of rotation during periods of sliding. As such, use of bi-center hole opening bits have increased in an attempt to drill and open the hole in one run with a directional motor. This paper documents the development of a unique bi-center design to provide not only reliable hole opening, but also high and consistent dogleg response on a motor assembly.
The project is focused on a drilling program within the Uracoa field in Eastern Venezuela (Figure 1). This application called for a build from vertical to horizontal, with maximum dogleg severity (DLS) requirement of 10.2deg/100ft. This had not been attempted in the past with bi-center bits, relying instead on conventional 8 ½" PDC bits. However, the operator had hole problems that made running 7" casing difficult in this section. To get the casing to bottom, a number of wiper trips were required to condition the hole.
In order to reduce the non-productive time, a bi-center and directional motor were selected by Petrodelta / PDVSA to eliminate the additional wiper trips required with the conventional fixed cutter (FC) bits: The 8 3/8 x 9 ½?? bi-center would effectively drill a larger hole size. The unique design selected features a mid-reamer section. This double profile design is considerably more stable than prior technology, delivering improved borehole quality and enhanced directional performance.
The initial application was extremely successful. The elimination of the wiper trips and hole problems considerably reduced drilling time for the section, and the casing took notably less time to run. This amounted to $960K savings compared to the field average and $1.69 million compared to the previous well drilled. In addition, the required DLS was achieved while increasing ROP by 58% compared to the field average.
The latest bi-center technology, in conjunction with Steerable motors, can deliver the required DLS and enlarged hole in demanding directional applications. This has proven to be an extremely cost-effective drilling system, saving nearly 10 days compared to the field offset.
Optimizing Gas Field Performance to Increase Gas Production Rates and Reserves
Authors: Stein M. H. , Venturini G. J. , Avasthi S. M. 
Published: May 2009

Abstract
Integrated asset modeling involves modeling performance from the reservoir to the completion, up the wellbore, through the facilities all the way to the plant inlet, and even up to the sales line. The integrated asset model consists of a coupling of different programs for each component of the operations, linked together through one computer program. The reservoir component may include reservoir simulation, or material balance. The well model represents inflow performance for the completion and wellbore hydraulics. For gas reservoirs, the reservoir and well models are typically coupled to a gas gathering system model, to predict pipeline pressure and temperature drop as well as model compression. A plant model can also be coupled to the gas gathering system model. The engineer adjusts the various models to match historical performance and then predicts performance for various operating scenarios. The goal for the engineer is to optimize performance within various facility and regulatory constraints, and determine how to maximize gas rates, reserves and profit.
This paper not only describes the integrated asset modeling process, but also describes case histories of how integrated asset modeling has been successfully applied to offshore and onshore gas reservoirs. A common objective in many of these case histories is to assess compression. Compression reduces bottom-hole flowing pressure and abandonment pressure, thereby increasing gas recovery factor. In one example, authors will show how the gas reservoirs of an entire offshore business unit in South America were tied together in a single integrated asset model. Each gas field was simultaneously optimized for the timing of compression to out run the aquifer and maximize gas recovery. Looping of a sub sea gas line was modeled to assure that the multiple gas field platforms did not bottleneck the sub sea gas lines.
Integrated asset modeling can also be used to manage daily gas reservoir operations. Integrated asset modeling programs have been linked to data automation systems. In one example, the integrated asset model calculated daily gravel pack erosion limits and the operator was able to maximize gas production rate without risking the sand control completion.
An Efficient Methodology of Production Strategy Optimization Based on Genetic Algorithms
Authors: De B. Nogueira P. , Schiozer D. J. 
Published: May 2009

Abstract
In this work a methodology of production strategy optimization, based on genetic algorithms (GA) is presented. The process aims to maximize the net present value (NPV) of the field and it is performed in terms of number and placement of wells. Independents optimization stages of quantity and placement of wells are alternated until the procedure convergence. The optimization stages of well placement are performed exclusively by a GA fitted with the goal of reducing the number of simulations needed for maximizing the NPV of the field. The optimization stage of quantity of wells may be carried out both by GA as an enumerative technique&lt;sup&gt;1&lt;/sup&gt;. The choice is made, automatically, for the method that requires the lowest number of flow simulations.
The proposed methodology is applied in a selection process of production strategy. A case that aims to check the potential of performance of two production strategies is examined. The first production strategy is composed exclusively by vertical wells while the second one is composed exclusively by horizontal wells. The proposed methodology is used in the optimizations, subsidizing the selection process of the production strategy.
It is possible conclude that the methodology proposed gives a greater efficiency and reliability to optimization processes of production strategy. In addition, with the automated procedure, it is possible to evaluate a greater number of possibilities, increasing the scope of search for the best production strategy.
Experimental Study on In-Situ Combustion of Brazilian Heavy Oil
Authors: Chicuta A. M. , Trevisan O. V. 
Published: May 2009

Abstract
The present work refers to an experimental study on oil recovery by in-situ combustion. A specific apparatus holding a combustion tube of 100 cm in length and 6.9 cm internal diameter was designed and constructed for the study. Experimental tests were performed with a heavy oil of 12.8°API from a Brazilian onshore field. Plain air was injected at a constant rate of 3 SLPM, while the production pressure was set at 10 bar.
The main purpose of this study was to survey the influence of clay content in the reservoir rock with initial oil saturations ranging from 25 to 50%.
The results indicate that the in-situ combustion method is technically applicable to the rock-fluid system tested. Moreover, the tests were useful in providing the proper range of parameters for the oxidation reactions to occur. Clay has proved to play a key role on fuel deposition and, consequently, on propagation of the combustion front. In a clean sandpack medium, the combustion front was not self-sustained, while in presence of clay, in amount ranging from 4.5 to 10.0% mass fraction, sustainable combustion reactions were achieved. Front peak temperatures were recorded in the range of 457 – 501 °C, and for oil recovery factors were greater than 84%. From the set of data collected during the tests, results show combustion front velocities to span between 14.1 to 18.3 cm/h. Worth mentioning, upgradings of 3.2° to 8.4° API were observed in the produced oil.
The basic combustion parameters - fuel consumption, air requirement, air-fuel ratio, atomic H/C ratio, oxygen utilization - obtained during the experiments are favorable to the implementation of in-situ combustion and shall be used as a guide to the pilot project planned for the field.
A Parametric Study of Solvent Injection as a Recovery Method For Heavy Oil and Bitumen Reservoirs
Authors: Oliveira M. F. , Barillas J. L. M. , Mata W. , Dutra T. V. 
Published: May 2009

Abstract
There is still a large amount of natural resources in heavy oil reservoirs which can be explored using new methods. However, this enormous amount of hydrocarbon resources which are in these reservoirs may be explored with new concepts. The VAPEX process is a promising recovery method. The process consists in two horizontal wells, parallel between themselves, producer and injector, where vaporized solvent is injected with the objective of reducing the oil or bitumen viscosity. The purpose of this work is to examine how some important operational and reservoir parameters influence the VAPEX process, in the produced oil rates, in the cumulative produced oil and in the recovery factor. Parameters such as the spacing between wells, the injection pressure, and type of solvent, oil viscosity, residual water saturation and horizontal permeability are addressed in this study. The choice of solvent to be used in the process was the factor that most significantly influenced the process, allowing a greatest recovery factor of oil. The largest cumulative oil recovered was obtained for other parameters of significant influence as the longest distance between wells, increased horizontal permeability and lower injection pressure.
Innovative Completion Design and Systematic Approach Improves Operating Efficiency and Enhances Well Productivity
Authors: Omonze D. U. , Jackson M. R. , Osorio G. , Blanco E. R. 
Published: May 2009

Abstract
Hydraulic Fracturing has always been referred to as a multidisciplinary technique for delivering improved well productivity. In the BP exploration business operation, a successful hydraulic fracturing operation is a key requirement for cost-efficient well project delivery. With formation rocks requiring in excess of 18000 psi bottom-hole treating pressures, reservoirs with contrasting formation pressure regimes, complex stress profiles and the need for multi-zone commingled completions as business drivers, significant challenges arise in terms of down hole equipment limitations, increased complexity in completion installations, high project costs and diminished assurance of fracture pumping completion success.
An innovative well completion design and a thorough multidisciplinary planning strategy dramatically improved operating efficiency and successfully enhanced well productivity for the Guadalupe sands in BP Colombia operations. The system was implemented in the Floreña C6 well in the Piedemonte Field in Colombia. The completion installation technique also represented the "first of a kind" globally and sets the pace for the future completion work to be undertaken in the Piedemonte Field.
This paper comprehensively describes the total system approach implemented in various disciplines and the strategic planning applied to overcome critical obstacles in the well delivery process; optimizing project costs and creating increased assurance for the hydraulic fracturing operations resulting in a remarkable well performance.
In-Depth Analysis of Depth-Based Data Solves Severe Vibration Issues Drilling Interbedded Sand/Shale Sequences in 3D-Directional Well Profiles
Authors: Armour J. E. , Sankar R. , Thomson I. , Ramchune D. , Sas M. 
Published: May 2009

Abstract
Drilling the 17 ½-in. deviated hole sections in the Cashima field, southeast offshore Trinidad presented a number of distinctive challenges. Unexpected vibration was hindering real-time logging capability, reducing tool life and compromising drilling performance, resulting in increased well costs. The operator required a Rotary Steerable System (RSS) and PDC bit combination that could efficiently deliver all directional objectives on a repeatable basis, without compromising downhole tool integrity. The BHA needed to maximize ROP and minimize vibration while drilling through the abrasive interbedded sand/shale sequence, where UCS varies from 2,500psi to 4,000psi every one or two feet.
Initially, it appeared that RSS reliability was the main issue limiting performance improvement, due to the occurrence of failures of RSS components on three consecutive 17 ½-in. sections. An application-engineering group conducted an in-depth analysis to identify issues limiting drilling performance. Memory data was analyzed to fully understand the complex downhole dynamics critical to increasing directional PDC efficiency. This analysis led engineers to determine that the root cause of tool failure and performance deterioration was severe vibration, which resulted from the bit's inability to smoothly transition between the interbedded formations.
Improved PDC technology was required without any drastic change in operating parameters. Bit improvements included a more abrasion-resistant polished cutter, unique depth-of-cut control technology and the use of secondary stability features. From the implementation of a more stable PDC bit design, the following benefits were realized while drilling the 17 ½-in. sections of the last two wells: the targeted TD on each well was achieved in one run, with minimal intervention of vibration control methods and no failures of RSS components. Comparison of the 17 ½-in. sections of six wells drilled during the Cashima project, where two different bits were used, revealed that there was a total reduction in cost per foot of 25%, and a total comparable savings of approximately 50 hours of non productive time or USD 1.25 million to the operator that could be attributed to the use of the different bits.
This paper will discuss the methodology used to optimize the 17 ½-in. bit for the Cashima offshore field.
Multiphase Simulation of Integrated Hydraulic Fracture/Reservoir Flows Applied to Sierras Blancas Retrograde Condensate
Authors: Fernandez G. , Lolley R. , Quintero A. , Araque-Martinez A. , Kennon S. R. 
Published: May 2009

Abstract
A new method is described that efficiently and robustly simulates multiphase flows in reservoirs with modern complex well completions, such as horizontal wells with transverse hydraulic fractures. These types of completions present a difficult challenge to simulators due to the enormous range of scales in geometry and permeability. For 30+ years, simulators have been restricted to very small ratios of smallest grid block to largest and have been unable to model completions faithfully. Simplified well models with added skin, such as the Peaceman model, have been approximations to real-world completions. The new method, based on a finite element method, manages a prodigious range of scales and correctly implements the physics of multiphase fluid flow.
This paper illustrates the new method in a practical setting: the current exploitation plan of the Sierras Blancas reservoir in Argentina, which requires the solution of reservoir flows coupled to hydraulically fractured vertical and horizontal wells. The models describing hydraulic fractures and reservoir are discretized with a finite element mesh that conforms to both reservoir and fracture geometries and smoothly grades down from reservoir scale to the interior of the hydraulic fracture. Flow inside the fracture is computed along with reservoir flow and is fully coupled.
The Sierras Blancas is a gas reservoir; in the course of exploitation, the hydrocarbon in place behaves as a retrograde condensate. The multiphase aspect of this fluid is modeled with an extended black-oil model wherein the PVT properties of the fluid are derived from lab measurements. As condensate drops out of the gas at the dewpoint, the character of the equations changes from single or two phase (gas, water) to two or three phase, and properties, such as Bg, have slope discontinuities that have historically presented formidable challenges to the numerical modeling of fluid flow. The new method correctly deals with both of these numerical difficulties and the attendant scale challenges.
The behaviour of existing wells in Sierras Blancas, along with hypothetical future, more-complex well designs, is modeled faithfully. Various scenarios are being run with these models being part of a continuous-improvement programme of development of the reservoir to optimize exploitation economics.
A Boundary Element Method Applied to Pressure Transient Analysis of Geometrically Complex Gas Reservoirs
Authors: Wang Haitao , Zhang Liehui 
Published: May 2009

AbstractMany scholars have used the boundary method to solve pressure transient problems of geometrically complex oil reservoirs. Their research mainly concentrates in oil reservoirs. However, the research on the pressure transient problems of geometrically complex gas reservoirs is very few. The description of pressure transient problems of gas reservoirs is more complex than that of oil reservoirs as the compressibility of gas and the variability of gas viscosity. By deriving rigorously in detail,this paper develops the Laplace space boundary elementary method for solving pressure transient problems in geometrically complex gas reservoirs. The corresponding boundary element models are built and solved. Type curves are computed and drawn. The characteristics of the typical curves are analyzed on the basis of fluid flow mechanism and flow process. The results of this paper not only help us to understand the fluid flow mechanism in this kind of geometrically complex gas reservoir but also can be applied to well testing. The results provide theoretical basis for people to scientifically and economically exploiting reservoirs. Besides, this paper theoretically proves the versatility of BEM in oil reservoir and gas reservoir seepage problems.
First Successful Drilling and Underreaming of Hard, Chert-Rich Formations
Authors: Perez C. , Escareno P. , Arias A. , Castellanos E. , Salazar J. , Urdaneta I. 
Published: May 2009

Abstract
Historically hole-opening and underreaming operations have been restricted to softer formations. This paper describes what is believed to be the first successful drilling and underreaming of a very hard, chert-rich formation.
Many producing wells have been drilled into the deep Cretaceous formations of south Mexico. These consist primarily of hard limestones containing dolomite stringers, large chert nodules, with very erratic hardness and some natural fractures; UCS estimates range from 17,000 to 30,000 psi. On average it takes three TCI bits and two or three PDC bits to drill the Cretaceous interval, which is typically from 4,800 m to 5,400 m TVD.
After several unsuccessful attempts to drill exploratory wells into Jurassic formations below the Cretaceous, the operator redesigned these wells with a contingency casing string. Rig hoisting limitations required each hole interval between conductor and the Jurassic to be underreamed – larger diameter casing strings could not be handled safely. This meant drilling the Cretaceous formation in 8 ½-in. hole and underreaming to 12-in. diameter in order to accommodate the desired 9 5/8-in. casing.
A new eccentric fixed-blade reamer and pilot PDC bit were designed for this application, using latest technology cutters, and profiles, cutter layouts and backrakes, which provided the highest possible durability and thereby gave the best chance of withstanding the high, erratic rock hardness and chert nodules.
The entire Cretaceous interval was successfully drilled and underreamed in a total of five runs. In each case, the assembly was tripped for logging, coring or section TD, with the pilot bit and reamer in good condition. Logging confirmed the desired 12-in. diameter hole. This case history confirms the ability to simultaneously drill and underream hard, chert-rich formations, in this instance greatly reducing the operator's risk of failing to reach their target and giving a wider range of completion options.
Use of Divergent Fluids as an Alternative for Enhanced Recovery in Naturally Fractured Cores
Authors: Lopera Castro S. H. , Restrepo A. , Ocampo A. F. 
Published: May 2009

Abstract
Gas injection is widely used in fields of oil exploration as a method for enhanced recovery. However, this method may be inefficient when producer rock forming favors gas channeling due to heterogeneities. Divergent fluids such as foams have been injected into this type of reservoirs to increase efficiency of scanning, either by reducing gas mobility or by blocking its flow through preferential channels, which can be individual fractures or natural fractures systems.
This study aims to evaluate the efficiency of foams in gas channeling reduction and increase of oil recovery in natural fractured porous medium. A methodology is designed for lab evaluation of foam stability at high temperature, as well as coupling of foam solution and formation fluids, restricting channeling of gas through the fracture(s) and obtaining parameters for optimal performance of tests adjusting to similar reservoir conditions. Using oil recovery as a parameter to measure efficiency of methods, we found that additional recovery is increased an average of 10% once fractures are closed with foam solution, in contrast to fracture closure by increasing of overload pressure. We could verify that foams act as an efficient fluid to block fractures which are common in the rock matrix. Use of divergent fluids allows the increase of crude oil in fractured reservoirs.