bluuebunny/crossref_metadata_2025_split huggingface dataset:
Large-Scale Evaluation of Alloy-Metal Annular Plugs for Effective Remediation of Casing Annular Gas Flow
Authors: Carpenter Robert B. , Gonzales Manny , Griffith James E. 
Published: December 2007

Abstract
Annular gas pressure, also known as sustained casing pressure (SCP), is a common problem and potential threat to the safety of personnel and equipment, as well as to the environment. Improved means of primary cementation and life-of-the-well simulations show promise for preventing future annular gas-flow problems. However, there has been little success in eliminating SCP, once developed, without jeopardizing the economic life of a well.
Possible solutions to SCP in the form of remediation include bullheading cement, injection of zinc bromide brines into the well's annulus, or use of expensive resins to seal the annulus. A proposed solution that can compensate for the drawbacks of the above options and has shown promise on small-scale physical models is palletized alloy-metal. This solution involves placing palletized alloy-metal into the well's annulus, heating the alloy-metal above its melting point, and then allowing the alloy-metal to cool. These steps form a continuous alloy-metal plug in the well's annulus.
Data and conclusions documented in this paper are from full-scale pipe-in-pipe and pipe-in-sandstone geometry models having the following scope:
Geometry of 5 ½ × 8 ½-in. pipe-in-sandstone and 10 ¾ × 13 ⅜-in. pipe-in-pipe configurations Model length limited to 15 ft and deviated at 30° from vertical Alloy-metal pellets placed and activated with water-based drilling fluid present in annuli Temperature limited to 200°F
Results are also documented by dissecting the models and photographing the exposed cross-sections. Information gathered in this testing will help with the field introduction of this technology.
New Treatments Substantially Increase LOT/FIT Pressures to Solve Deep HTHP Drilling Challenges
Authors: Webb Sid , Anderson Tom , Sweatman Ron , Vargo Richard 
Published: December 2007

Abstract
Insufficient borehole pressure integrity (BHPI) is a major drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in California and other areas. Shale and sandstone formations with low BHPI may be weakened by leaking faults/ fractures or poor rock properties, causing lost returns with mud weights close to pore pressures. Drilling through depleted or low pore pressure formations with some probability of drilling into higher pressured zones in the same hole section compounds the severity of this challenge in the Temblor formation in Kern County, California.
This challenge was solved by an innovative treatment applied in the Berkley East Lost Hills No. 1 well. Compared to conventional methods, it increased leakoff test (LOT) and formation-integrity test (FIT) pressures to incremental values higher than those typically seen in the industry. Increasing BHPI allowed an additional 960 ft to be drilled before a 7-in. liner was set, and the well was drilled to 19,724 ft. This depth met the objective of the well (to obtain full penetration through the objective sands) and allowed the subsequent discovery of a pay zone. If the new treatment to increase the LOT had not been used, the 7-in. liner would have been set early, and it is unlikely that the discovery zone would have been penetrated.
Preventing skin and formation damage in potential zones of interest while treating weak points was another major concern heightened by a wide range of pore pressures. This paper discusses a theoretical mechanism to help explain how the treatment rapidly and substantially increases pressure integrity across both sand and shale formations. Minor penetrations in high and low-permeability sandstone-core tests help explain why the treatment system minimizes or prevents skin damage. Skin damage in the zones of interest may be prevented or minimized by BHPI treatments that only enter leaking fractures or faults.
Further development and deployment of BHPI treatment technology promises a step-change in industry practice to optimize well plans with lower cost programs for drilling fluids, casing design, cementing, and completion equipment. Optimized well designs should reduce both drilling days and flat time by allowing operators to drill smaller-diameter holes while using fewer casing strings to achieve the same production-string dimensions.
An Analytical Solution to Estimate the Optimum Number of Development Wells to Achieve Maximum Economical Return
Authors: Corrie R. D. 
Published: December 2007

Abstract
The preliminary estimate of the number of wells required to exploit a reservoir is one of the most important variables needed to decide on an oil field development. Traditionally, the optimum number of wells has been determined graphically from a plot of economic return verses well spacing. This paper derives an equation to solve this problem directly without the plot and presents an illustrative example for its application. The independent variables of the equation are the reserves, the initial production rate per well (assumed to decline over life), the oil price at wellhead, the total present value cost per well and the interest rate.
Optimisation of Emissions Through the Application of a Mobile Variable Tip Flare System
Authors: Manning Julian 
Published: December 2007

Abstract
Increasing legislative requirements on a global basis are driving the development of innovative solutions to reduce emissions. Flaring and venting of waste hydrocarbon gases is a known contributor to pollution and increasing pressure is being exerted onto operators to monitor and minimise emission levels.
BJ Process and Pipeline Services operate a "Hi-Lo" variable tip flare system which has proven to achieve outstanding emission results during a number of separate operations, including the incineration of Butadiene / Styrene waste gas during a plant shutdown and flaring high Hydrogen Sulphide concentration gas during a production well test. The system has many applications to allow the safe flaring or incineration of waste gases where stringent emission results need to be constantly demonstrated.
The fully portable system is automated using a comprehensive Programmable Logic Controller (PLC) package to constantly monitor and control gas flow, percentage of air mixture, auxiliary fuel gas concentration and the positioning of the variable tips to maintain constant tip velocity.
The paper discusses the systems effectiveness, design, applications and an analysis of the emission results achieved in comparison to legislation.
Imaging through Crude Oil with High Resolution, Optically
Authors: John A. Hother 
Published: December 2007

Abstract
We have combined our expertise in space-imaging technologies and our knowledge of oilfield industry needs to create an imaging technology that can produce high-resolution optical images through crude oil.
The first application we have explored is a new form of downhole video that requires no preparation of the well (ie no flushing), saving time and cost in interventions. The new technology opens-up many further instrumentation possibilities for the oil industry.
The results of the feasibility study demonstrate the high quality images that can be achieved through crude oil.
Now we are developing a trials prototype in a Joint Industry Project, sponsored by Amerada Hess, BP, Chevron and Shell.
Modeling and Mitigation of Severe Riser Slugging: A Case Study
Authors: Meng Weihong , Zhang Jeff J. 
Published: December 2007

Abstract
In offshore oilfield development projects using subsea tiebacks, severe riser slugging is of great concern, particularly for flowlines with downward slope at the riser base. In a recent conceptual design for a deepwater field, the flowline system consisted of a downward pipeline about 2,100m long and a steel catenary riser in 700-m deep water. Transient flow analysis indicated that severe riser slugging would occur. The paper describes the analysis of several mitigation techniques - increasing well lift-gas injection rate, injecting lift-gas at riser base and reducing riser diameter.
The study revealed that these severe slug mitigation techniques reduced the slug volume and frequency with different efficiencies. For the particular case study, increasing the lift gas at wellbore bottom of 1 MMSCFD from the base case of 3 MMSCFD was the most efficient technique to eliminate severe slugging. Riser base gas lift required 3 MMSCFD in addition to the 3 MMSCFD lift gas at the bottom of wellbore. Mitigation by reducing riser diameter was not effective because it required a 2" reduction in the diameter and would make flowline pigging difficult. The analysis also showed that including the wellbore in transient flow models for the short-distance flowlines is essential. Without the wellbore model, no severe riser slugging was predicted.
Integrated History-Matching of Production and 4D Seismic Data
Authors: Gosselin Olivier , van den Berg Stanislas , Cominelli Alberto 
Published: December 2007

Abstract
The reservoir characterisation methods are still improving the integration of all available data for more accurate predictions, but the history-matching confrontation between observed and simulated data as predicted by the model remains the crucial test. Time-lapse 3D seismic data now provides a new type of information on the dynamics of fluids in the reservoir, relating variations of seismic signal to movement and/or depressurisation of hydrocarbons. This powerful reservoir-monitoring tool can be fully exploited when it is used to update the reservoir model in an integrated matching loop of all history data – 4D data, spatially distributed over the whole reservoir, jointly with time series of well observations. In a classical gradient-based minimisation of an objective function, measuring the mismatch between observed and simulated data, we add a seismic term to the well term. This contribution, defined in terms of elastic parameter variations within the reservoir, comes from an inversion of the seismic signals. On the other hand the fluid flow simulator is coupled with a petro-elastic module to convert the simulated saturation/pressure and static rock properties into simulated elastic properties. The optimiser uses gradients of both terms to minimise the global mismatch, updating the reservoir properties. In this paper, we justify our approach using elastic parameters, describe the relationships to derive elastic properties from reservoir properties, and present the integrated iterative loop matching both kinds of dynamic data (production and 4D seismic), based on sensitivity analysis to select the most efficient parameters and applied to the synthetic PunqS3 case6,1.
The Development of a Major Gas-Condensate Field
Authors: Saadawi Hisham 
Published: December 2007

Abstract
A major grass-root gas project has been recently implemented to develop two condensate reservoirs in a field onshore Abu Dhabi. The project facilities comprise of a gas gathering system, a processing plant for condensate recovery and an injection system to recycle the lean gas back to the reservoir.
This paper addresses the basic design concepts and describes the surface facilities. The paper also outlines the project implementation strategy as well as the commissioning and start up experience.
Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commerical-Scale Field Demonstration Project
Authors: Reeves Scott R. 
Published: December 2007

Abstract
Coalseams represent an attractive opportunity for near-term sequestration of large volumes of anthropogenic CO2 at low net costs. There are several reasons for this: Coals have the ability to physically adsorb large volumes of CO2 in a highly concentrated state.Coals are frequently located near large point sources of CO2 emissions, specifically power generation plants.The injection of CO2 into coalseams actually enhances the commercial methane recovery process.The recovery of coalbed methane is enhanced when the injected gas contains nitrogen, a major constituent of power plant flue gas.
A joint U.S. Department of Energy and industry project to study the reservoir mechanisms and field performance of CO2 sequestration in coalseams has recently been initiated. The project involves laboratory and field-testing to define critical reservoir mechanisms, including multi-component (CO2-CH4-N2 ternary) sorption behavior. Two existing fields in the San Juan Basin, the most prolific coalbed methane basin in the world, are currently under CO2 and/or N2 injection. These two fields, the Tiffany Unit (operated by BP) – now under N2 injection (but with mixed CO2/N2 injection being studied), and the Allison Unit (operated by Burlington Resources) – under CO2 injection since 1995 will be thoroughly studied via reservoir simulation to understand CO2 sequestration and enhanced coalbed methane recovery performance, using both pure CO2 and N2, as well as CO2/N2 mixtures. This paper presents the fundamental reservoir mechanisms of CO2 sequestration and enhanced recovery of methane from coalseams, and the field performances to date of the Tiffany and Allison Units.
Responsible Environmental Management Leads to Improved Resource Recovery - The Laminaria / Corallina Gas Re-Injection Project
Authors: Ryan S. A. , Twartz S. K. , Gordon D. M. 
Published: December 2007

Abstract
This paper presents a study of a gas re-injection project, designed with the dual objectives of emissions reduction and enhanced oil recovery in an Australian offshore oil field. A significant reduction in greenhouse gas emissions has been achieved since the project commenced late in 1999, with some 1.3 million tonnes of CO2 emissions avoided in year 2000 alone. Miscible displacement is expected to add around 6 million barrels to ultimate recovery from the Corallina reservoir, and use of stored gas as fuel is expected to achieve significant reductions in operational expenditure later in field life.
Gas injection for the purposes of enhancing oil recovery has been common oilfield practice for several decades. Many technical papers have been written on this subject, from both theoretical and practical points of view. Projects that focus exclusively on greenhouse gas control (either by sequestration or emission reduction) are less common, although the level of research is rapidly increasing as environmental awareness spreads throughout the industry. The Laminaria / Corallina gas re-injection project is designed to achieve both objectives.
Reservoir Monitoring Methodology for a Giant Gas Field
Authors: Potapieff Igor , de Wit Joop 
Published: December 2007

Abstract
The Tunu field is the major gas supplier of the East Kalimantan system (Indonesia). Production commenced in 1990 and more than 200 wells have been drilled to date. The field exported an average 1.3 Bcf/d in 2000.
In 1999, an extensive reservoir-monitoring program was launched: successful implementation of Multi-Rate Production Logging (MRPL), creation of reporting templates for MRPL and Pressure Build Up (PBU).
This well-defined standardised process has resulted in a significant enhancement of the reservoir description and understanding of the production performance with extensive use of classical reservoir monitoring tools. Well operations have also been streamlined and optimised.
So far, approximately 150 PBU and 40 MRPL have been fully processed, with presently 5 MRPL's acquired per month.
Microbial EOR Study to Improve Sweep Efficiency In Caltex Fields. Phase I - Nutrient Selection
Authors: Kadarwati Sri , Udiharto M. , Hs Noegroho Hadi , Brinkman Joseph P. , Yulianto Bangun 
Published: December 2007

Abstract
The objective of this research is to find a cost effective nutrient that will stimulate the growth of in-situ microbes in Caltex Pacific Indonesia (CPI) oil fields to create sufficient biological products to plug high-permeability reservoir thief zones. If successful, injection fluids may be diverted into unswept regions of the reservoir, increasing the sweep efficiency and extending the production life of watered-out oil fields. This paper describes how a wide range of nutrients were researched and tested in the laboratory to achieve the objective. The primary findings of this study show that several nutrients were successful at creating bioproducts at high temperature, low salinity, reservoir conditions, and that molasses may be the most cost effective nutrient for all three CPI waterflooded reservoirs tested: Balam South, Bangko, and Minas fields. As a result of this work, laboratory studies were started to see to if the microbial growth created in laboratory test tubes can be recreated within reservoir core plugs to achieve sufficient permeability reduction to justify field trial(s). The core flood process and techniques will be presented in a separate paper.
Openhole Expandable Sand Screen Completions in Brunei
Authors: Lau Hon Chung , Van Vliet Jacques , Ward Mike , Morin David , Djamil Arifun , Kuhnert Paul , Aldaz Walter , Shanks Steven 
Published: December 2007

Abstract
Expandable Sand Screen (ESS®) was deployed successfully as a sand control device in two horizontal openhole completions in two geologically different offshore fields in Brunei. A critical success factor was the choice of a drill-in-fluid (DIF) that maintained hole stability and gave a near-gauge hole during running and expansion of the ESS. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based DIF for the other well. Challenges unique to the deployment of ESS in these wells are discussed.
Effective Thru Tubing Gravel Pack Methods in Attaka Field
Authors: Lee C. C. , Darby M. C. , Popp T. R. 
Published: December 2007

Abstract
Effective sand control has long been a concern within unconsolidated sandstone formation in the Attaka Oil field in East Kalimantan. Many of the producing wells have stopped production due to the influx of formation sand. These wells have low rate marginal reserves, which cannot economically justify re-completion with conventional gravel packing techniques.
Two Thru-Tubing Gravel Pack (TTGP) completion methods utilizing 1.5" Coiled Tubing (CT) were introduced in Attaka Field with selective based on the wellbore configuration. These techniques utilize methods transferred from Unocal's Gulf of Mexico operations. The first method is a Pack-off Method with gravel pack screen and packoff assembly for use in the monobore completion. The second method is a vent screen utilizing a mechanical plug back tool (MPBT) that can be run through 3-1/2" production tubing into 7" casing.1 The sand retention performance after the TTGP completions have been exemplary. Production tests show an increase in net production rate that is in line with inflow calculations. This paper reviews the job design, operational procedure and observed results of these two successful TTGP methods in the Attaka field. Six case histories and conclusions from the overall results are also presented.
A newly developed visco-elastic surfactant-based (VES) polymer-free fluid was used as the gravel carrier fluid. Rheology, fluid loss and gravel settling data are presented.
New-Generation Underbalanced Drilling 4-Phase Surface Separation Technique Improves Operational Safety, Efficiency, and Data Management Capabilities
Authors: Bullock Ray , Karigan Joe , Wiemers Tim , McMillan Scott 
Published: December 2007

AbstractDuring the past five years, it has been well documented that drilling in underbalanced wellbore conditions can increase well productivity. This finding has led to a resurgence of interest in applying this concept. In wells where relatively high rates of produced hydrocarbon are anticipated, however, the traditional drilling flow-back systems have not always been successful in providing the safety, operational efficiency, and data management capabilities needed.This paper focuses on a new, built-for-purpose, underbalanced drilling, 4-phase, surface-separation and well-control system that couples the mechanical flow requirements of the underbalanced drilling environment with the safety and efficiency of a process facilities design.The discussion will focus on the design intent, prototype testing, commissioning and first operations of the system.The system incorporates: Progressive separation and solids-handling techniques to improve separation efficiency.Programmable Logic Controller (PLC) technology to improve operational safety in the event of emergency or process upset conditions.Strict adherence to codes and industry practices, ASME B&PV (pressure vessels), ASME B31.3 (piping systems), API RP 14C (surface safety systems), NACE MR0175 (H2S service metallurgy), API RP 500 (Electrical Installations), etc.State-of-the-art real time data acquisition, data transmission and reservoir modelling techniques to better control the drilling process.The system can safely and efficiently control and measure all returns, both drilling and production, while wells are being drilled by underbalanced means.The system was designed and built in 1999 and underwent pre-commissioning and testing in December of that year. Pre-job commissioning was carried out in two locations during the first and second quarters of 2000.The system provides a fully integrated underbalanced surface system capable of meeting the requirements of today's prolific underbalanced drilling candidates. Since commissioning, the system has been used on several underbalanced wells, and the results of the first deployments demonstrate that underbalanced drilling programs exhibiting high rates of produced hydrocarbon on surface can be undertaken without compromising operational safety, flexibility and integrity. Elements of data such as reservoir pressure; flow rates; gas composition; and mechanical drilling data can be incorporated into a single job database that can facilitate on-site data access, data manipulation, data transmissibility and analytical capability. Thus, timely and more effective on-site decision making results.
Simultaneous Snubbing and Drilling Operation on Long Reach Multi Lateral Improves Field Economics
Authors: Tupper Dale , Anderson Bryan 
Published: December 2007

Abstract
When Petronas Carigali, the national oil company of Malaysia, planned the development of its platform EWDP-A offshore Sabah, they did so on the basis of using coiled tubing for any thru-tubing workover operations which were needed while the drilling rig was still in place. In this way the drilling rig could be fully utilized for drilling operations, thus maximizing the efficiency of, and minimizing the total time for, the development. Well EW 117 was completed on this platform as a level 6 Multilateral in July 2000 with dual 3-1/2" tubing strings accessing two laterals with measured depths of 14,910ft. and 15,236ft., respectively. The clean-out and perforation operations commenced with coiled tubing with the rig assisting. However, due to a combination of the tortuosity and the lengthy horizontal sections of the laterals, it was not possible to reach bottom with coiled tubing because of the high frictional forces encountered.
After consideration of several alternatives a feasibility study was undertaken to explore the possibility of using a Hydraulic Workover (Snubbing) unit to perform the -thru-tubing operations concurrent with the continuing drilling activity. The study concluded that, with some custom designed handling equipment, a special tapered workstring and strict adherence to a permissible concurrent activity matrix, this approach was indeed feasible. The operation was performed in February 2001 and the well made available for production by the beginning of March. Throughout the workover operation the drilling rig sequence remained in accordance with plans, apart from a period of 14 hours downtime while moving the Snubbing unit into its working location.
This paper will review the problem encountered, the motive forces applicable, the feasibility study and the resultant custom designed equipment and workover operation. It will discuss on the integrated team approach and detailed planning, in which active participation from Petronas Carigali, the drilling contractor and several service companies resulted in a successful operation.