bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Downhole Annular Pressure Measurements to Anticipate Drilling Problems
Authors: Hutchinson Mark , Rezmer-Cooper Iain 
Published: December 2007

Abstract
Downhole annular pressure is becoming a standard measurement in all drilling environments. When monitored in the context of other drilling parameters, and with a fundamental understanding of hydraulics principles it is possible to identify undesirable drilling conditions, suggest remedial procedures, and help prevent serious problems from developing. For wells with only a small difference between fracture gradient and pore pressure, drilling without realtime downhole annular pressure information may not be possible. Indeed, this is particularly true for extended reach wells, for high temperature / high pressure (HTHP) wells, and in deep water environments where large flowing friction pressure losses or very narrow pressure margins can exist.
Previous publications have discussed how with realtime downhole annular pressure measurements a driller can more effectively maintain the equivalent circulating density (ECD) and equivalent static density (ESD- when not circulating) within a desired range in order to prevent lost circulation and maintain borehole integrity (including managing swab, surge and gel breakdown effects). Annular pressure data are used to evaluate the effects of flow and pipe rotation on the ECD, and to evaluate formation integrity tests. With accurate downhole data the driller can apply conventional drilling practices more effectively to reduce both rig time and potentially also the number of required casing strings.
In order to interpret annular pressure measurements it is important to first understand the physical hydrodynamic principles. It is also important to analyze pressure data in the context of all downhole and surface drilling parameters.
Recent experiences with downhole pressure data have demonstrated how ECD trends can be used to anticipate drilling problems before they develop into serious events. Even with the ECD within its desired range, drilling problems not apparent from conventional procedures can be anticipated.
We present three case histories. The first is from an extended reach drilling project where the annular pressure data gave advanced warning of high cuttings loading, and helped avoid a potential lost circulation or stuck pipe event. This example also illustrates the significant flowing pressure losses that can occur along an extended reach wellbore. A second case history demonstrates the importance of using annular pressure measurements in deep water environments both to establish and maintain safe pressure margins. Downhole pressure data can also be used to evaluate kill procedures. The final example was from an extended reach well where the drilling fluid had sagged during a bit trip, and shows how by evaluating downhole annular pressure measurements, safer and more efficient tripping practices can be developed.
P. 535
Pilot Study Results to Convert Oil Field Produced Water to Drinking Water or Reuse
Authors: Doran Glenn F. , Williams Kimberly L. , Drago Joseph A. , Huang Sunny S. , Leong Lawrence Y.C. 
Published: December 2007

Abstract
The project goal is to convert a currently unusable by-product of oil production, produced water, into a valuable drinking water resource. Results from a 10 gpm pilot study were used for a conceptual design and cost estimate for a 44,000 bpd treatment facility. Generally, the pilot study demonstrated that by altering operating conditions, the treated water could meet industrial, irrigation, and drinking water quality standards. Four scenarios were evaluated, 2 industrial and one each for irrigation and drinking water. The total project cost estimates, with an accuracy of approximately -15 to +30 percent, ranged in capital cost from $3.1 to $12.3 million with an O&M cost ranging from 4.5-23.4 c/bbl of water treated.
P. 403
Yme, A Marginal Field Development in the North Sea
Authors: Apeland Odd J. , Flaate Svein , Skoglunn Tom 
Published: December 2007

Abstract
The small Yme oil field offshore Norway was discovered in 1987, but the Plan for Development and Operation (PDO) was first submitted in 1993 due to the field's marginal character. The recoverable oil reserves as basis for the PDO were only 3,4 mill. Sm3. With the field located far from infrastructure, the development decision required a dedicated effort from the license owners.
Focus was put on increasing and firming up the reserves basis while maintaining acceptable production costs. Accordingly, a jack-up drilling rig was leased and modified for simultaneous drilling and production. An oil tanker was leased for storage and field off-loading. The time from contract awards to first oil from the main structure, Yme Gamma Vest, in February 1996 was only 13 months.
An important part of the development strategy in order to improve profitability was active exploration of mapped prospects in the license area in parallel with field development activities and production. The first subsea satellite development, Yme Beta Ost, was put on production in June 1996. This was only nine months alter submitting the PDO to the authorities and three months after production start for the main field. During the production phase three more exploration wells have been drilled. Overall, these have increased the reserves basis and prolonged the field lifetime.
The Yme reservoirs comprise several challenges such as low reservoir pressure and solution gas content, special fluid properties such as high salinity of the formation water with dissolved solids of 190.000 ppm, and high asphaltene content of the oil. Artificial lift using ESPs and subsea gas lift was installed from the start. A compact water injection unit contributes to improved oil recovery. Barefoot open hole multilateral horizontal completions and hydraulic fracturing of vertical wells have also been used to improve drainage from the reservoir which has large permeability contrasts.
The Yme field development shows how a marginal offshore field development can be initiated and improved using decision making under risk and application of unconventional techniques.
P. 447
Drilling Applications of a New Logging-While-Drilling Slim Sonic Tool: Two Case Studies
Authors: Tepper R. , Boonen P. , Bean C. , Hollon D. 
Published: December 2007

Abstract
A logging-while-drilling (LWD) slim compensated long-spaced sonic tool that can be run in boreholes as small as 5 3/4 in. has been found to have useful drilling applications in the Gulf of Mexico. The 4-3/4-in.-OD tool features a two-transmitter, four-receiver acoustic array. Alternate firings of the two transmitters yield two sets of four waveforms that are processed downhole with a semblance correlation technique to compute compressional and shear slowness ranging from 40 to 180 microseconds/ft. The waveforms are stored in memory for advanced processing at surface. Applications of the sonic information include real-time processing of synthetic seismograms, prediction of pore pressure, computation of acoustic porosity from compressional and shear slowness, and determination of rock mechanical properties for borehole stability analysis. The first of the two studies underscores the accuracy of the LWD slim sonic slowness measurements in predicting pore pressure and detecting the top of supernormal pressure. An LWD slim resistivity tool was run simultaneously with the LWD slim sonic tool, and the resulting resistivity data verified that the slowness measurements indeed served as valid pore-pressure predictors. Operationally, the LWD slim sonic device can be positioned close to the bit, and the measured slowness values can be pulsed uphole in real time during drilling. To enhance drilling efficiency and safety, pore-pressure software at the rig calculates formation pressure and an equivalent mud weight. The second study presents an unusual case in which LWD slim sonic data were used to confirm that a 190-ft section of casing, believed to be cemented in place, slid 90 ft down the wellbore.
Pressure-Transient Analysis for Perforated Wells
Authors: Yildiz Turhan , Ozkan Erdal 
Published: December 2007

Abstract
This study presents a 3D analytical model to analyze the transient flow into perforated vertical wells. The model considers arbitrary phasing angle, non-uniform perforation size and length, and formation damage around perforations. The characteristics of transient pressure and derivative responses of perforated wells are investigated and the flow regimes are documented. Asymptotic approximations for each flow regime are provided. A sensitivity study is carried out to identify the impact of various reservoir and completion parameters on the transient pressure and derivative responses as well as the productivity of the well. It is observed that convergent flow into perforations significantly influences the early-time and intermediate-time pressure responses. A pseudoskin expression to be used to estimate the inflow performance of perforated vertical wells is also presented.
Incorporating Seismic Data of Intermediate Vertical Resolution Into 3D Reservoir Models
Authors: Behrens Ronald A. , Tran Thomas T. 
Published: December 2007

AbstractThree-dimensional (3D) earth models are best created with a combination of well logs and seismic data. Seismic data have good lateral resolution but poor vertical resolution compared to wells. The seismic resolution depends on seismic acquisition and reservoir parameters, and is incorporated into the 3D earth model with different techniques depending on this resolution relative to that of the 3D model. Good vertical resolution of the seismic data may warrant integrating it as a continuous vertical variable informing local reservoir properties, whereas poor resolution warrants using only a single map representing vertically averaged reservoir properties. The first case best applies to thick reservoirs and/or high-frequency seismic data in soft rock and is usually handled using a cokriging-type approach. The second case represents the low end of the seismic resolution spectrum, where the seismic map can now be treated by methods such as block kriging, simulated annealing, or Bayesian techniques. We introduce a new multiple map Bayesian technique with variable weights for the important middle ground where a single seismic map cannot effectively represent the entire reservoir.This new technique extends a previous Bayesian technique by incorporating multiple seismic property maps and also allowing vertically varying weighting functions for each map. This vertical weighting flexibility is physically important because the seismic maps represent reflected wave averages from rock property contrasts such as at the top and base of the reservoir. Depending on the seismic acquisition and reservoir properties, the seismic maps are physically represented by simple but non-constant weights in the new 3D earth modeling technique.Two field examples are shown where two seismic maps are incorporated in each 3D earth model. The benefit of using multiple maps is illustrated with the geostatistical concept of probability of exceedance. Finally a postmortem is presented showing well path trajectories of a successful and unsuccessful horizontal well that are explained by model results based on data existing before the wells were drilled.
Simulation of a CO2 Flood in the Slaughter Field with Geostatistical Reservoir Characterization
Authors: Prieditis J. , Yang A.P. 
Published: December 2007

Abstract
Texaco has been operating a CO2 flood in the Sundown Slaughter Unit in Hockley County, Texas since January of 1994. The CO2 flood was originally justified by analogy with an adjacent CO2 flood. A CO2 flood simulation was later done to predict and optimize the performance of the flood. With actual production data from the CO2 flood available, the simulation forecast was redone and updated. Specific objectives of this new, revised simulation study were to use geostatistical reservoir characterization to improve the representation of reservoir heterogeneity and to use more representative relative permeability curves and residual saturation values.
A team was formed for the new simulation study which included both geologists and engineers with members both from the operating division and Texaco's research organization. Four new geostatistical reservoir models were developed, each with a different level of effective heterogeneity. The basic idea was to adjust the reservoir characterization to improve the CO2 flood match and forecast. All the new models as well as the old model could be used to match the waterflood history equally well with moderate adjustments in the water-oil relative permeability curves. The correct level of reservoir heterogeneity was not needed to do a waterflood match. However, all the models were not equally valid in matching and predicting CO2 flood performance. The predicted CO2 flood performance was substantially different for these models and indicates that a good waterflood history match is not sufficient for a good CO2 flood prediction.
Having actual CO2 flood production response data proved to be the key factor in choosing a model with the correct level of heteogeneity and generating an improved CO2 flood forecast. A successful match of the actual CO2 flood response could not be obtained with the original model but could be with two of the new geostatistical models. The reservoir heterogeneity in a model must be substantially correct for a successful CO2 flood match. The predicted CO2 flood production response was initially fairly close to the actual for these two models, but the match was improved with adjustments of the gas relative permeability curve. In addition, adjusting the gas relative permeability curves to match the initial CO2 flood response brought the ultimate tertiary oil and CO2 production forecasts much closer than they had been initially. Adjusting the gas relative permeability curve for a CO2 flood history match can compensate for moderate, but not large, errors in the reservoir heterogeneity.
This paper describes the methods used for conducting the waterflood and CO2 flood history matches, for making the CO2 flood forecast, and for evaluating the different geostatistic realizations. In addition, the important sensitivities of a tertiary CO2 flood forecast to the reservoir description and the gas relative permeability are discussed and quantified.
P. 487
Enhanced Mechanistic Model and Field Application Design of Gas-Liquid Cylindrical
Authors: Gomez L.E. , Mohan R.S. , Shoham O. , Kouba G.E. 
Published: December 2007

Abstract
An existing mechanistic model for prediction of the hydrodynamic flow behavior in a Gas-Liquid Cylindrical Cyclone (GLCC) separator has been enhanced. The main enhancement incorporated is a flow pattern dependent nozzle analysis for the GLCC inlet for the prediction of the gas and liquid tangential velocities at the GLCC entrance. A state-of- the-art computer simulator, with appropriate graphical user interface, has been developed based on the enhanced model. The code, in an Excel-Visual Basic platform, can be used as a design tool. Four typical field GLCC systems have been designed for actual industrial applications. These include multiphase metering loop with both single-phase and multi phase flow meters, and pre-separation and full separation configurations. The field applications demonstrate the GLCC capabilities and its potential impact in the petroleum industry.
P. 533
Dynamic Simulation and Control System Design for Gas-Liquid Cylindrical Cyclone Separators
Authors: Wang S. , Mohan R.S. , Shoham O. , Kouba G.E. 
Published: December 2007

Abstract
Gas-Liquid Cylindrical Cyclone (GLCC) separator performance can be considerably improved by adopting a suitable control strategy to reduce liquid carry-over into the gas stream or gas carry-under into the liquid stream. A dynamic model for control of GLCC liquid level and pressure using classical control techniques is developed in this paper for the first time. Detailed analysis of the GLCC control system stability and transient response indicates that liquid level control could be achieved effectively by a control valve in the liquid outlet for gas dominated systems or by a control valve in the gas outlet for liquid dominated systems. Based on the proposed linear control system model, the system performance is simulated using a suitable software design tool. The novel control system design approach presented in this paper forms a framework for the GLCC active control system optimization.
P. 545
The Impact of Production Sharing and Other Non-Traditional Agreements on Investment Community Performance Statistics
Authors: Young E.D. , McMichael C.L. 
Published: December 2007

Abstract
Hydrocarbon reserves and the ability to product them profitably are the lifeblood of the upstream petroleum industry. Aggressive competition, ever sharpening scrutiny by the investment community, and volatile product prices drive companies to search for attractive new exploration and producing venture opportunities that will add the greatest value for a given investment. Production sharing and other related non-traditional agreement types have become popular given the flexibility they provide the host country in tailoring fiscal terms to fit their sovereign needs. However, actual agreement terms, including those that relate to royalty payments, cost recovery, profit sharing and taxes, can have a significant impact on the statistics that the investment community utilizes to access and rank the performance of a petroleum company. This paper examines the impact these terms and product price volatility on investment community performance statistics such as reserves replacement, unit exploration, development, and operating costs and earnings. Representative examples are utilized to demonstrate the variation in these performance statistics with variations in product price. Limitations in the various indicators are highlighted as part of the discussion.
P. 575
Application of Downhole Electric Heat Trace System in Arctic Completions
Authors: Fox James B. , Earsley Joseph D. 
Published: December 2007

Abstract
Approximately 30 downhole electrical heat trace systems are currently being utilized for the purpose of; freeze protection, mitigation of hydrate and heavy hydrocarbon accumulation in tubing strings, and viscosity reduction in the completions producing from the Schrader Bluff formation in the Milne Point field. To accomplish the intended objectives the current system utilizes a self-limiting heat trace cable strapped to outside of the tubing to a depth of 2260′. These systems have become an integral part of the completion design for production from these shallow, relatively viscous oil formations under arctic conditions. As the field progresses towards higher hole angles and new types of electric submersible pumping (ESP) systems the utilization of these systems become more critical. Electrical impedance heating systems, recirculation of heated side stream, periodic hot oiling, chemical treating, and mechanical scraping have been utilized as alternatives but the heat trace system has operationally been the most effective method for these purposes.
Downhole Tiltmeter Fracture Mapping: A New Tool for Directly Measuring Hydraulic Fracture Dimensions
Authors: Wright C.A. , Davis E.J. , Weijers L. , Golich G.M. , Ward J.F. , Demetrius S.L. , Minner W.A. 
Published: December 2007

Abstract
A new fracture diagnostic technology for mapping hydraulic fracture dimensions is introduced: downhole tiltmeter fracture mapping. Downhole tilt fracture mapping involves deploying wireline-conveyed tiltmeter arrays in offset wellbores to measure hydraulic fracture growth versus time. This technology has been employed to map over 100 fracture treatments in the last eighteen months. Allowing, for the first time, the gathering of statistically significant data-sets on how hydraulic fractures actually do grow - albeit, within only a few fields so far. In addition to providing fracture diagnostic data (fracture length, height, width and asymmetry), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with insitu observations of fracture growth.
The mapping concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) versus time and depth and inverting the data to obtain the created fracture dimensions. The principles are the same as for surface tiltmeter mapping, but the different array geometry make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline arrays, processing and modeling), present three field case studies, and briefly discuss the implications on fracture modeling.
P. 585
Carthage Cotton Valley Fracture Imaging Project - Imaging Methodology and Implications
Authors: Walker R.N. , Zinno R.J. , Gibson J.B. , Urbancic Ted , Rutledge Jim 
Published: December 2007

Abstract
SPE Paper 38577 introduced the Carthage Cotton Valley Hydraulic Fracture Imaging Project and described the initial imaging work. This paper describes the most recent methodology and implications of imaging hydraulic fractures utilizing microseisms recorded by extensive sensor arrays. Initial imaging work utilized a forward modeling approach. This paper will report further on confirmation of the event locations by inversion methods and by using decimation studies. A source parameter analysis will also be presented. Cotton Valley fracture treatments were performed at depths near 10,000 ft and imaged with arrays cemented in offset wells approximately 1300' away. Several techniques are utilized in both event location analysis and in analyzing certain characteristics of the events. These methodologies provide interpretations of the actual fractures and therefore have implications in the design and modeling of fractures. This paper will also point out and verify the need for development of an economical and commercial service to image fractures in real time. Decimation studies utilizing fewer optimally spaced receptors will determine the ability to develop a commercial service.
Imaging of the hydraulic fractures at the Cotton Valley test site provides conclusions not easily accepted. Issues such as asymmetry, dimensions of the fracture and growth characteristics all prove to be substantially different than expected. Findings such as these will affect modeling techniques, design parameters, and eventually well spacing and development plans. Accurate mapping of a fracture will provide conclusive information that can be utilized to develop optimized and efficient fracture treatments. More effective fracture treatments will result in reduced well costs which allow field extension and expansion opportunities.
Any operator or service company should apply lessons learned and presented in this paper. Imaging of the fracture and analysis of the actual failure mechanisms will provide a basis from which to design and model fractures in the Cotton Valley formation. Ideas for technology and completion strategies could be applicable to tight gas sand completions in other areas. This paper will show technical contributions such as:State of the art technologies utilized for mapping of the fractures.Analysis techniques that will be paramount in the future development of a commercial fracture mapping technology.Event parameter analysis yielding deductions concerning actual failure types in the rock.
These analyses will have a major impact on fracture design and modeling.
P. 599