bluuebunny/crossref_metadata_2025_split huggingface dataset:
Portfolio Optimization: Systems vs. Sequential Approach
Authors: Al-Harthy M. H. , Khurana A. K. 
Published: December 2007

Abstract
Traditional investment decisions in the oil and gas industries ignore dependencies and interactions between parameters such as reserves, production and economics. In a previous paper1 we have shown that for a single project the system stochastic approach better captures the impact of dependencies and interactions among the components of decision parameters compared to the sequential approach and improves decision quality.
In this paper we build on the previous work and investigate the impact of system stochastic and sequential stochastic modeling on the portfolio efficient frontier. We use a stochastic integrated model, which captures uncertainty for a mix of five hypothetical offshore oil field development projects. The model combines reserves, production, capital and operating costs into an integrated probabilistic economic evaluation. The output of the stochastic model is used as input into the Markowitz Mean-Variance model and varying our company's participation level in the five projects to compute the efficient frontier.
The results show that the two approaches yield substantially different efficient frontiers. As expected the difference between the systems and sequential approach increases with increasing standard deviation of the portfolio NPV with the expected value of portfolio being greater in the systems approach. In our example, the difference in the computed expected NPV ranged from 8 % at lower level of risk to 15% at higher level.
In conclusion, the system approach is superior in capturing intra-project dependence and its impact on the portfolio level is significant compared to the sequential approach. Both the systems approach and the portfolio methodology complement each other in capturing both intra-project and inter-project dependence at the portfolio level.
Fracture Model for General Offshore Applications
Authors: Kaarstad E. , Aadnoy B. S. 
Published: December 2007

Abstract
The complexity of oil and gas wells has increased significantly the past decades. In addition to improved equipment, a better understanding of the subsurface environment is required to drill these wells efficiently.
Two modelling activities have been pursued in Norway the past decades: 1) Establishing a fracturing model for shallow penetration offshore, and 2) develop a fracture model for deepwater drilling.
Data from seabed investigations and from conductor and surface casings were collected and normalized for varying water depths. This model works well and has been used for many years. When deepwater drilling started in 1997 the same concept was applied. The results show that the same type of model applies also for deepwater drilling.
Wells from Norway, UK, the Gulf, Angola and Brazil have been analyzed. They show remarkably similar behaviour when the water depth is considered.
This paper brings this work further by presenting a generalized fracture model for relaxed depositional environments that works for all water depths. Normalization methods will be presented so fracture data can be converted to other water depths (serve as prognosis for new wells), based on rig floor elevation, water depth, differences in overburden stresses, and on mud properties.
Several field cases will be presented with water depths ranging from 380 m to 1350 m, demonstrating the wide applicability of the new model.
It will be shown that the generalized fracture model provides a good correlation with an error within a few percent.
New Gun-Hanger Design Provides Safety and Flexibility for High-Rate Gas Wells in North China Kela Field
Authors: Hales J. , Smith I. , Wah Kee Yong , Xun Liu Jian , Yong Li Ru , Qiu Liu Ming 
Published: December 2007

Abstract
Tarim Oil Company, a major producer in northwest China, operates the Kela II field in the remote province of Xinjiang. Their completion program required underbalanced perforating for several large-volume gas wells with estimated record breaking flow rates. To support the operational priorities on safety, reliability, and flexibility in the completions, options for perforating were limited to wireline-deployment and modular gun-hangar systems so that gun removal would be possible if any nonconformity occurred. To obtain the maximum well production after perforating, it was imperative that minimal wellbore damage occur. Killing the well was not a viable option since the reservoir properties in the Kela field are fluid sensitive. Therefore, killing the well after perforating underbalanced would increase near wellbore damage and produce a higher skin.
This paper will discuss the two wells completed in this field using a newly developed perforating method. There were four wells developed, but two were completed by another perforating service provider. The expected production from each well was ∼4 MMscf/d. Production from the two wells completed with the methods described in this paper exceeded expectations by 46% with a rate of 5.85 MMscf/d at full open choke with a 5 MPA drawdown. The production from the two other wells that were perforated using other methods fell short of expectations with rates of less than 4 MMscf/d.
Data Acquisition With Advanced Acoustic Telemetry Improves Operational Efficiency in Deep-water and Land-Well Testing—Case Histories
Authors: Azari M. , Salguero A. , Almanza E. , Kool H. 
Published: December 2007

Abstract
A new Acoustic Telemetry System (ATS) that obtains realtime bottomhole pressure and temperature data without the use of wireline has been introduced to the oilfield. Traditionally, wireline has been used to acquire bottomhole surface read-out (SRO) data in real time during well-test operations using either a wireline-deployed downhole inductive system or a download probe in close proximity to the transmitting device operations. The operational hazards possible when using wireline in deep water subsea safety systems have increased safety risks in certain applications.
This paper discusses a new system that uses acoustic telemetry and operates with either down-hole latching or with a download probe located in close proximity to the transmitting device. The system was designed for land rigs, offshore jack-up rigs, and deepwater floating rigs. In addition to wireless data transmission to surface, the system has downhole memory gauges that record data independent of the real-time SRO interval rates. The system is also capable of bi-directional acoustical communication, which allows commands to be sent from surface to operate downhole instruments.
The quality of data compares excellently with downhole memory gauge data. Other operational advantages of the system include the fact that 1) testing equipment can be in the well prior to firing the perforating guns, 2) reduced rig time can reduce operational costs, and 3) personnel and environmental safety are increased. In case of transmitting the data via the wall of the testing pipe, there is no need for a probe or latching device.
The two case histories, which are presented in this paper, will describe system use and will verify its advantages.
A Generic Solution to Bottomhole-Assembly Modeling
Authors: Wu M. , Chen D. C. -K. 
Published: December 2007

Abstract
This paper presents industry's first generic algorithm using Lubinski's equations for Bottom-Hole Assembly (BHA) modeling. The algorithm is designed to "self-structure" the BHA model by dividing complicated BHA configurations into independent modules and segments. Modules are bounded by two stabilizers where segments are bounded by BHA components such as stabilizers, bends, and cross-overs, etc. A recursive process is used to derive solutions for each of the segments and modules, one at a time, starting from the top of the BHA (tangential point) down to the bit. Only two unknowns (and two non-linear equations) are left when the recursive process reaches to the bit. The two unknowns are then solved by iteration. As a result, the entire process is robust and extremely computational efficient. The most significant advantage of the new algorithm is probably its accuracy as attributed to the use of closed-form equations. Field data has confirmed that the algorithm is more accurate than the commonly used finite-element based BHA programs especially for the steerable motor systems and rotary steerable systems.
The Feasibility Studies of Polymer Foam Flooding in Gudao Oilfield
Authors: Li Zhenquan , Zhou Guohua , Zhou Zongming 
Published: December 2007

Abstract
Gudao oil field is one of the major production areas in Shengli Field. After 20-year development, most of reservoirs are characterized by high water cut, poor sweep efficiency and inefficient oil recovery due to the high heterogeneity.
The goal of this paper is to present the results of laboratory and field studies of polymer foam flooding in Gudao oilfield. For polymer foam, the displacement medium is N2 mixed with surfactant as foaming agent and polyacrylamide. Polymer foam can increase the sweep efficiency and control gas mobility by selective gas blocking and high apparent viscosity. The experimental investigation studied the use of additives to enhance foam properties and the factors affecting blocking performance such as injection model, gas liquid ratio, and alternate slug, etc. The oil displacement experimental results showed that the previous bypassed low permeability areas in polymer flooding could be swept by polymer foam displacement, and thus increasing oil recovery.
The scaled-up laboratory data has been successfully applied in a field test. After 3 months of injecting polymer foam, the daily oil production increased from 75.1 t/d to 141.4 t/d, while water cut decreased from 93.9% to 88.1%. The above results demonstrate that enhanced foam flooding is a promising method for producing highly heterogeneous reservoirs and to improve the reservoir sweep efficiency after polymer flooding.
Results of Proactively Managing a Heavy-Oil Waterflood in South Oman Using Streamline-Based Simulation
Authors: Naguib M. , Sikaiti S. , Balushi H. , Barrio C. , Mahrooqi S. , Batycky R. 
Published: December 2007

Abstract
Streamline simulation is an ideal reservoir management tool for mature waterfloods since it can identify unswept reserves, quickly evaluate multiple forecast scenarios, and provides novel information like well-pair interactions. The identification of well-pair interactions is particularly useful as it allows for pattern surveillance, quantifying offset production with injection volumes, and identifying efficient vs inefficient areas of injection.
The Thuleilat heavy-oil field consists of 120 wells and is geologically complex with stacked reservoirs, multiple oil-water contacts, and numerous faults, making it difficult to identify well interactions and areas of unswept reserves. However, being a dead oil reservoir with the majority of production a result of injection, it is ideally suited for streamline simulation. Several opportunities were identified based on the streamline simulation. These opportunities, which generally apply to all waterfloods, could be divided into well rate target recommendations, pattern optimization, producer-injector conversions, and infill locations.
Pattern optimization opportunities resulted in a 10% gain in the offset oil producers. In one of the pattern optimization activities three water injectors were identified for injection rate increase, followed by optimization activities in the associated oil producers which resulted in a significant oil gain. Other pattern optimization activities were to close in high gross rate wells and diverting the flow toward offsets oil producers. One of the trials was to close-in one of the producers in the central area for one week, which resulted in a measurable oil gain in 3 offset oil producer wells. The second activity was closing another producer in the northern sector for two weeks which resulted in an oil gain in 5 offset oil producers. Further use of the streamline model includes the assessment of unswept reservoirs for infill locations and the estimation of water cuts for development locations.
Drilling Riser Alternative Repair Methods for Leaking Joint Seals Utilizing Pressure Activated Sealant Technology
Authors: Cary D. Neil , Groomer Vic 
Published: December 2007

Abstract
Since the inception of deep water operations, drilling riser seal component failures have been a persistent problem worldwide. Traditionally these failures have required that the drilling riser be pulled, the affected seals replaced and then the drilling riser re-installed; resulting in substantial rig down time and expense to the operators and service companies. Seal-Tite International has developed a unique array of pressure activated sealants able to withstand the high pressure and extreme temperature conditions associated with subsea drilling and production operations. The sealant is polymerized by the differential pressure created through the leak sight. The polymerization process only occurs in the sealant that passes through the leak sight; all other sealant remains liquid and can be circulated out of the well with no damage to any of the well components. Subsequent to extensive testing, pressure activated sealant technology was utilized to repair a leaking joint in a drilling riser choke line at approximately 4200 ft water depth in the Gulf of Mexico. The leak was repaired and the client was able to continue and complete drilling operations with no downtime. The riser was tested to operating pressure every three days for the duration of the drilling operation with no leaks observed.
Experimental Study of Effective Hole Cleaning Using "Sweeps" In Horizontal Wellbores
Authors: Valluri S. G. , Miska S. Z. , Ahmed R. , Yu M. , Takach N. E. 
Published: December 2007

Abstract
Drilling fluid "sweeps" are specific fluids specially formulated to transport cuttings that cannot be removed by ordinary drilling fluid circulation. There has been a lack of certainty of the "sweep" type selection in the field. Although they are in common use in vertical and deviated drilling operations, not much information is known regarding the use of "sweeps", especially in terms of "efficiency" of the "sweeps" and the specific hydraulics involved.
The effect of rheology of the "sweep" fluid on "sweep efficiency" has been investigated under low pressure ambient temperature (LPAT) and elevated temperature elevated pressure (EPET) conditions. The LPAT tests were conducted on a 90-ft-long transparent test section that consists of an 8″ ID casing and 4.5″ OD drill pipe. To investigate the effect of temperature on the "sweep efficiency", EPET experiments were conducted under simulated downhole conditions. The University of Tulsa Advanced Cutting Transport Facility (ACTF) flow loop (73-ft-long test section with annular geometry of 5.76″ × 3.5″) was used to simulate downhole conditions. Three types of sweep tests were conducted with six drilling fluids that have different rheological parameters.
LPAT test results are presented in terms of weight of cuttings removed from the annulus, measured cutting bed height and differential pressure. Results of EPET experiments are presented in terms of cuttings concentration in annulus and differential pressure.
Through the rigorous experimental work conducted, it has been identified that within the test conditions "high viscosity" "sweeps" in the absence of drill pipe rotation proved to be ineffective in bed erosion and cuttings removal. In addition to a higher flow rate, low concentrations of polymer, i.e. "less viscous sweep" and drill pipe rotation greatly improve "sweep efficiency". Finally, recommendations are made for practical field operations.
An Effective Horizontal Well Completion and Stimulation System
Authors: Seale R. , Athans J. , Themig D. 
Published: December 2007

Abstract
Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling has led the way, with current technology capable of drilling thousands of feet laterally through a hydrocarbon reservoir. Second, has been completion and stimulation advancements. 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 not candidates for horizontal drilling. Developments in completion and stimulation technology specific for horizontal drilling have broadened the application range for the technology.
Until recently there have been two completion and stimulation option. The horizontal can be completed open hole, or with slotted or perforated liner. This has essentially negated any effective stimulation along the entire length of the horizontal wellbore. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. This requires multiple coiled tubing trips along with multiple rig up and rig down of the stimulation equipment involved. These multi-stage horizontal completions take weeks to complete at high cost 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 detail a new completion system which is run as part of the production liner, which does not require cementing and provides positive mechanical diversion at specified intervals, so fracturing and stimulations can be pumped effectively 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.
Research Study for Microbial Restoration of Methane Deposit with Subsurface CO2 Sequestration into Depleted Gas/Oil Fields
Authors: Fujiwara K. , Mukaidani T. , Kano S. , Hattori Y. , Maeda H. , Miyagawa Y. , Takabayashi K. , Okatsu K. 
Published: December 2007

Abstract
Research into the microbial restoration of methane deposits has been carried out since 2003. The objective of this research is to estimate the possibility of microbial restoration of methane deposits using subsurface sequestered CO2 and indigenous anaerobes in depleted oil and gas fields. The most important factors are the efficiency and velocity of methane conversion by indigenous anaerobes inhabiting a reservoir.
Fluid samples (producing oil and water) from gas and oil fields in Japan were collected and analyzed in order to clarify the existence and survivability of indigenous hydrogen- and methane-producing anaerobes under severe reservoir conditions (high temperature and high pressure). PCR-DGGE analysis, a molecular biology method, was applied to reservoir samples such as reservoir brine, crude oil and producing water from the gas/oil fields. Some hydrogen-producing thermophilic bacteria (HPTB) and methane-producing thermophilic archaea (MPTA) which participate in the microbial restoration of natural gas were detected at the DNA level in some of the samples. Isolation of HPTB and MPTA was also attempted individually, and two strains of HPTB and one strain of methanogen were successfully separated.
Subsequent to these findings, accelerated hydrogen- and methane-producing experiments, using glucose as a carbon source, have been conducted at the laboratory level to estimate the potential for microbial methane production under actual reservoir pressure and temperature (5MPa, 50°C) and the rock pore as micro culture space. Experiments, using the isolates described above and active anaerobes which were not isolated from the reservoir brine, indicated that microbial hydrogen- and methane-producing efficiency and velocity are relatively high even in various reservoir conditions. Furthermore, if a suitable and economical carbon source is available, depleted oil reservoirs are potentially good candidates to become subsurface microbial reactors, using hydrogen- and methane-producing indigenous anaerobes containing HPTB and MPTA to convert injected CO2 into methane.
Engineered Cement Set Control Additive—Solution for a Long Standing Cementing Challenge
Authors: Moradi Sara , Zonzee Peter , Sandhu Depinder , Elarda Hussein , Jain Bipin , Salazar Jose 
Published: December 2007

Abstract
Cementing long zones with a single slurry system is a very challenging problem that has been known in the industry for many years. The main difficulty is related to the large temperature differential between the bottom and the top of the long cement column. The cement slurry is typically designed to have a thickening time to allow placement at the bottom hole circulating temperature. However, the same slurry when exposed to the much lower temperature that exist at the top of the cement column may not set for several days. This can lead to long waiting on cement resulting in rig non productive time or in certain cases can lead to well integrity problems.
Another known problem in the industry is setting of cement plugs in an environment where the bottom hole temperature is not well known. This scenario may exist while setting unplanned kickoff plugs or plug and abandonment of wells. The thickening time of slurries retarded with conventional additives are sensitive to temperature and therefore uncertainties in bottom hole temperature may lead to excessive setting time or premature setting, both of which can be costly.
A new generation of engineered cement set control (ECSC) additive has been developed to resolve the problems mentioned above. The ECSC additive provides thickening times that are almost independent of temperature thus allowing efficient and reliable cementing of long cement columns, where there is a large temperature differential between the top and the bottom. The ECSC additive will also minimize setting problems in situations where the bottom hole circulating temperature is not known accurately.
This paper presents the results of a successful field application of the ECSC additive to cement long casing sections in fields in the Middle East. The well designs require the reliable isolation of long casing/liner sections in order to safeguard well integrity and meet well construction objectives. Field implementation, results including logs from the wells are presented.