bluuebunny/crossref_metadata_2025_split huggingface dataset:
History matching Using Time-lapse Seismic (HUTS)
Authors: Gosselin O. , Aanonsen S. I. , Aavatsmark I. , Cominelli A. , Gonard R. , Kolasinski M. , Ferdinandi F. , Kovacic L. , Neylon K. 
Published: December 2007

Abstract
This paper describes the results of a two-year EC-sponsored project which uses new information provided by repeated seismic acquisitions (4D seismic data) jointly with production data in an extended, efficient and consistent history matching process. This process involves a simultaneous minimisation of the mismatch between all types of measured and simulated data. A gradient-based technique has been developed and tested both in a prototype and in commercial computer-aided history matching software. We show results on real cases, located in the North Sea and the Adriatic Sea, and discuss key issues of such seismic history matching.
Most applications of time-lapse seismic to date have been qualitative or semi-quantitative. We propose a quantitative workflow. The seismic contribution in the objective function is defined in terms of elastic parameter variations within the reservoir and the data have been properly scaled using an estimate of seismic uncertainty (covariance matrix). The "observed" values are obtained by inversion of the seismic signal. For the "modelled" values, the flow simulator is coupled with a petro-elastic model to convert simulated fluid and static rock properties into simulated elastic properties.
The techniques described in this paper allow us to reconcile production history matched models with 4D information, and to reduce the uncertainty in reservoir properties, which haven't a real impact on the well history, but which significantly drive future behaviour of the field. This is a further step towards the necessary integration of available data for better predictive simulations. Focusing on quantitative combined with qualitative use of data enhances the multidisciplinary approach.
Updating Stochastic Reservoir Models With New Production Data
Authors: Fenwick D. H. , Roggero F. 
Published: December 2007

Abstract
In current practice history matching is often performed on upscaled reservoir models without updating the original geological model. Taking into account new production data in an existing model is often problematic because of the lack of appropriate techniques. This problem becomes crucial when using geostatistical models. In such a case, the integration of new static and dynamic constraints requires the modification of an initial realization without destroying the initial history match and the overall geostatistical properties.
This paper presents a new methodology based on advanced history matching techniques for updating dynamically 3D stochastic reservoir models to account for new production data. The proposed approach is based on the gradual deformation method. It allows local or global smooth transformations of the model while conserving the overall statistical characteristics. History matching is performed by coupling this method with an optimization process which integrates geostatistical modeling, upscaling, and fluid flow simulation in the same loop. This approach provides great flexibility in history matching various types of production data. In addition, inversion parameters can be selected throughout the entire modeling loop, from the facies spatial distribution, to petrochemical parameters and fluid flow parameters. Finally, local transformations may be performed to account for new wells or to update the reservoir model with new dynamic information.
A successful application to a 3D stochastic reservoir model inspired from a real field is presented. The first step was to perform a history match using the production history available from an initial group of production wells. Then, new dynamic information is acquired from infill wells and over one year of additional production data. The heterogeneity distribution is locally modified by gradual deformation to update the model with this new information. The benefit of the proposed approach for improving the model characterization and reducing uncertainty on production forecasts is demonstrated.
What is the Real Measure of Gas-Well Deliverability Potential?
Authors: Kabir C. S. 
Published: December 2007

Abstract
This paper probes the usefulness of establishing the traditional time-variant, absolute-open-flow potential (AOFP) on a given well. Our contention is that a well's AOFP is not a measure of its future potential in a volumetric system owing to ever declining reservoir pressure. To circumvent this reality, we suggest a two-step approach. First, conduct a multirate test to establish reservoir parameters, such as permeability, static and non-Darcy skin, and average pressure. Second, with these known parameters, use an analytic tool to describe the deliverability potential for a well or a group of wells, including reservoir uncertainty and/or operational constraints.
This paper presents a simple methodology for establishing reservoir parameters and predicting a well's future deliverability potential. Field examples show that computing reservoir parameters from buildup and drawdown data and establishing the deliverability relation instills confidence in analysis. We also show that the traditional log-log graphing of the backpressure equation is no longer required, because we avoid the notion of a stabilized deliverability concept.
An analytic reservoir simulator was developed to handle well location in various drainage shapes using the pressure-transient analog for rate computation. Material balance calculations form the backbone when depletion sets in. This simulator is also capable of handling uncertainty of various input parameters and performs full-factorial design calculations for a three-level design; that is, p-10, p-50, and p-90. This feature facilitates capturing uncertainty of drainage area, and/or any other variables while predicting future rates.
A Systematic and Comprehensive Methodology for Advanced Analysis of Production Data
Authors: Mattar L. , Anderson D. M. 
Published: December 2007

Abstract
This paper is a comprehensive presentation of ALL the methods available for analyzing production data, highlighting the strengths and limitations of each method. These methods include those developed by Arps, Fetkovich, Blasingame and Agarwal-Gardner, as well as a new method called the Flowing Material Balance. Some methods yield recoverable reserves, while others give hydrocarbons-in-place.
Traditional (Arps) decline analysis (exponential or hyperbolic) gives reasonable answers in many situations, but has its failings, the most important one being that it completely ignores the flowing pressure data. As a result, it can underestimate or overestimate the reserves.
The increase in electronic data measurements has made the flowing pressure as readily available as the flow rate. This enables the use of the more sophisticated methods of analysis, which take into account both the flowing pressure and the production rate.
The sequential and systematic use of all these methods gives a consistent and more reliable answer. The strengths and limitations of each method are reviewed, from the simplest exponential decline to the Flowing Material Balance. Two examples are given, one that overestimates reserves, and one that underestimates them. An additional example illustrates the importance of knowing the dominant flow regime.
Transient Analysis of Tight Gas Well Performance – More Case Histories
Authors: Arévalo-Villagrán Jorge A. , Cinco-Ley Heber , Wattenbarger Robert. A. , García-Hernández Francisco , Samaniego-Verduzco Fernando 
Published: December 2007

Abstract
Production data from some gas fields show the presence of long-term linear flow for several years in a large number of wells, caused by the extremely low permeability in the reservoir. Long-term linear flow production may be generated and controlled in some cases by the reservoir geometry; in others it is controlled by the natural occurring reservoir properties. In this paper three physical scenarios that cause and control long-term linear flow in tight gas reservoirs are described. First, we analyze how parallel natural fractures lead to permeability anisotropy which causes long-term linear flow. An analytical matrix-parallel fracture model is presented. Second, we show how a fractured well in a tight gas reservoir causes linear flow perpendicular to the fracture. We focus on decline curve analysis methods for long-term linear flow in fractured tight gas wells. Third, we discuss long-term vertical linear flow in a high permeability streak in tight gas reservoirs. An analytical model to analyze long-term linear flow in a high permeability layer and 2D simulation results are shown. Formulas to estimate reservoir properties for both fractured tight gas wells with linear flow and vertical linear flow in a high permeability streak are shown. These formulas were developed for both infinite acting and closed reservoirs, under either constant bottomhole flowing pressure or constant gas rate conditions. A linear analysis can be applied to detect where the outer boundary effect occurs, by finding the slope of a [m(pi)-m(pwf)]/qg vs. t1/2 plot. Values of k1/2Ac, drainage area, and OGIP can be estimated without knowing prior porosity, permeability, and thickness. Application of this linear analysis to production analysis for conventional and tight gas wells and validation of the results by using numerical simulations are shown.
Separating the Signals from Clay Bound Water and Heavy Oil in NMR Spectra of Unconsolidated Samples
Authors: Manalo F. , Ding M. , Bryan J. , Kantzas A. 
Published: December 2007

Abstract
Low-field nuclear magnetic resonance (NMR), whether implemented in a logging tool, bench top analyser or on-line sensor, cannot detect the complete response of heavy oil or bitumen. Both heavy oil and bitumen relax quickly so the spectra from these samples at room temperature appear mostly at relaxation times less than 10 ms. The contribution of heavy oil to the NMR spectrum is distinct in samples that are free of clays or contain bulk water and it is consequently possible to calculate oil and water content based on NMR spectra. Solids content is then determined by difference. However, samples that contain clays and/or relatively little water produce spectra that are more difficult to interpret because the relaxation times of clay bound water are in the same range as bitumen. Experimental results from mixtures containing a layer of illite, kaolinite or montmorillonite in sand exposed to mild brine shows clay bound water to have a characteristic response. These NMR "signatures" were used to develop predictive nomographs of clay content. A second set of experiments involved adding heavy oil to the same samples and the changes in NMR spectra after exposure to heavy oil were compared to the spectra obtained before oil was added. The differences identified in this work allowed for improvements in calculating water, oil and/or solids content and a preliminary predictive algorithm for clay content determination is presented. The purpose of this work is to allow one to more accurately separate the contributions of heavy oil and clay bound water despite the fact that these will overlap in an NMR spectrum from a sample. Improved characterization of oil sands and recovery from these formations are possible consequences of this work.
A Next-Generation Wireline NMR Logging Tool
Authors: DePavia L. , Heaton N. , Ayers D. , Freedman R. , Harris R. , Jorion B. , Kovats J. , Luong B. , Rajan N. , Taherian R. , Walter K. , Willis D. , Scheibal Jeffrey , Garcia Serena 
Published: December 2007

Abstract
This paper discusses design and implementation of a new-generation nuclear magnetic resonance (NMR) wireline logging tool. The tool is a multifrequency, eccentered gradient-field design with multiple depths of investigation (DOI) spanning a range of several inches. The broad range of DOIs enables radial profiling of saturation distribution and formation damage. Because of the eccentered mode of operation and sensor design, the DOIs are maintained regardless of hole size and temperature. The DOIs range from 1 to 4 in.
The tool features multiple sensors, including a large antenna for fluid characterization and complementary small-aperture antennae for high-resolution acquisition modes. The sensors can be operated either separately or simultaneously at logging speeds of up to 3,000 ft/hr. Comparison of the responses is used to provide high-resolution identification of long T1 fluids such as light hydrocarbons.
New NMR acquisition sequences such as Diffusion Editing (DE*) are readily implemented on the new tool, which has a highly flexible pulse programmer. Combining the new acquisition methods with the multifrequency capability of the tool and Magnetic Resonance Fluid (MRF*) characterization processing provides robust fluid saturation and oil viscosity answers.
Monitoring Fracturing Fluid Flowback and Optimizing Fracturing Fluid Cleanup in the Bossier Sand Using Chemical Frac Tracers
Authors: Woodroof R. A. , Asadi M. , Leonard R. S. , Rainbolt M. 
Published: December 2007

Abstract
Proper fluid and proppant placement are crucial to a successful propped fracture stimulation. Numerous completion diagnostic technologies are available to characterize the placement of the treatment. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and anecdotally monitored in the field. A technique utilizing a family of unique, environmentally friendly, fracturing fluid compatible, chemical tracers has now been developed for quantifying segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. East Texas Bossier Sand case histories demonstrate that individual, chemically-differentiated and/or proppant-differentiated, fracturing treatment segments are often not being effectively recovered. It has also been demonstrated that the chemical make-up and/or the proppant scheduling of these individual fracturing fluid segments may not only be detrimentally effecting their incremental cleanup but ultimately the production contribution from the corresponding portions of the fractured reservoir. The validation of improvements in fracturing fluid cleanup and production enhancement resulting at least in part from changes in the chemistry of the fracturing fluids and/or changes in proppant scheduling are demonstrated using the tracer technology.
Improved Microseismic Fracture Mapping Using Perforation Timing Measurements for Velocity Calibration
Authors: Warpinski N. R. , Sullivan R. B. , Uhl J. E. , Waltman C. K. , Machovoe S. R. 
Published: December 2007

Abstract
A method is decribed where microseismic mapping of hydraulic fractures is improved by using crosswell data to calibrate and/or verify dipole-sonic velocity data. The microseismic technique uses an array of advanced tri-axial receivers to detect microearthquakes induced by a fracture and, thus, provides a real-time image of the fracture and the way it propagates. To apply this technique, the orientation of the receivers must be determined by detecting perforations or other energetic sources in the treatment well, and the velocity structure of the intervening rock interval must be adequately known. Currently, dipole-sonic logs provide high-resolution velocity data, but significant errors may occur if the logs are old (e.g., formation has depleted), anisotropy is large (e.g., vertical velocity different from horizontal velocity), or several other conditions exist. In addition, faults or lithology changes may separate the wells and alter the velocity structure. Accurate location of the microseisms, and thus the fracture image, is strongly dependent on accurate information about the velocity structure.
In the perforation-timing procedure, crosswell-velocity data are obtained by monitoring the firing pulse from the receiver-orientation perforations (or string shots) and recording the timing pulse along with the arrival data. From these results, a simple one-dimensional model of velocities can be extracted and used to validate, refine, or correct the detailed dipole-sonic data or provide a warning of discrepancies. The ultimate goal is improved accuracy in microseismic mapping, but the results are also useful for assessing the applicability of dipole-sonic logs. Perforation-timing measurements for velocity structure have now been performed in 10 separate projects that have been used to analyze approximately 120 fracture treatments.
Optimizing Fracture Stimulation in a New Coalbed Methane Reservoir in Wyoming Using Treatment Well Tiltmeters and Integrated Fracture Modeling
Authors: Mayerhofer Michael , Stutz Lloyd , Davis Eric , Wolhart Steve 
Published: December 2007

Abstract
This paper covers the optimization of hydraulic fracture treatments in a new coalbed methane reservoir in Wyoming. A multi-well pilot project was conducted in the Copper Ridge field to assess future development potential. Hydraulic fracture mapping was successfully performed with treatment well tiltmeters on six wells including the first-ever use on propped treatments. The mapped fracture height was then used to calibrate the fracture model, perform on-site frac design changes and optimize future fracture treatments. This paper shows how early use of fracture diagnostics can assist in the development of a new reservoir.
Closing the Gap: Fracture Half Length from Design, Buildup, and Production Analysis
Authors: Barree R. D. , Cox S. A. , Gilbert J. V. , Dobson M. 
Published: December 2007

Abstract
It is commonly observed that hydraulically fractured wells perform as though the effective fracture half-length were much less than the designed half-length. This observation has been explained by various "models" including poor fracture height containment, poor proppant transport, proppant falling out of zone (convection), ineffective proppant pack cleanup, capillary phase trapping, multi-phase flow, gravitational phase segregation, and non-Darcy flow, with combinations of any of these mechanisms. With recent improvements in diagnostic measurements of fracture geometry, some of these explanations have lost credibility, but the problem of low effective fracture length persists.
This paper presents detailed evaluation of hydraulically fractured well behavior using continuous production analysis, pressure transient (buildup) analysis and fracture treatment evaluation using actual field data from a tight-gas reservoir in the Rocky Mountain Region. The various analyses explain the observed producing behavior of the well and lead to a consistent determination of the actual "effective" fracture halflength compared to the physically created or propped length. Problems relating to semantics and inconsistent fracture and reservoir description, especially the physical processes encompassed by various analytical techniques, will be addressed.
Methods will be outlined for predicting the useful effective length from available proppant conductivity data. The process outlined helps to close the gap between designed frac length and producing length and points out the causes for remaining system bottlenecks that limit post-frac well productivity. Finally, the understanding of these mechanisms provides a means to arrive at an economic optimum fracture treatment design for a reservoir, once key parameters are known.
Managing Uncertainty Related to Hydraulic Fracturing Modeling in Complex Stress Environments with Pressure-Dependent Leakoff
Authors: Johnson Raymond L. , Greenstreet Carl W. 
Published: December 2007

Abstract
This paper demonstrates where alternate approaches to BHTP analysis and modeling can provide significantly differing potential stimulation treatment geometries, outcomes, and go-forward strategies. We will illustrate this conundrum using cases from the greater Cooper/Eromanga Basin of Central Australia; these cases commonly indicate an interrelationship between production outcomes, the magnitude of in-situ stress and the onset pressure or severity of pressure-dependent leakoff. Historically, treatments can be placed in these environments either after performing numerous diagnostic injections, by increasing pad volumes or by increasing injection fluid viscosity. However, these repeated injections and design alterations may only serve to stabilize the injection environment potentially masking the problem or causing production damage.
We offer recommendations and explore different methods to mitigate these effects in cases where high stress and pressure-dependent behavior are indicated. We demonstrate how strain-corrections are used to correct log-derived rock mechanical properties to history-match initial BHTP responses. The cases presented use either: (1) increases in near-wellbore or near-fracture reservoir pressure; (2) changes in stress due to fracture propagations or horizontal loading; or reductions in pressure-dependent leakoff coefficients to history match subsequent injections over multiple days. Finally, we indicate for each of these complex cases where production results or the desired treatment outcomes may have been altered by repeated diagnostic injections or a job changes.
Implementation of a Robust Deepwater Sand Monitoring Strategy
Authors: Nisbet William J. R. , Dria Dennis E. 
Published: December 2007

Abstract
Sand detection data has traditionally been used to protect asset integrity and prevent hydrocarbon release by limiting the potential for erosion of chokes, piping and valves. However, now in the Shell's Deepwater Gulf of Mexico oil and gas fields there is an additional need to ensure well integrity by appropriately characterizing the produced solids in order to monitor completion integrity and the effectiveness of bean-up rate and drawdown-constrained production operation schedules. The procedure developed within Shell allows us to critically evaluate how much and what type of solids are produced during choke changes and during sustained high-rate production, to differentiate between damaging solids and benign solids (small size or non-reservoir sand), and to monitor the wells for the onset of damage to sand-control integrity (sand control is generally required in Gulf of Mexico unconsolidated sands).
Our detection system combines an acoustic sensor, a slip stream device to sample solids entrained in the flow stream, and a unique on-site microscopic analysis to identify the solids that have been collected. In addition to the off-site calibration and testing of acoustic sensors, we perform field calibrations by injecting into the flow line, upstream of the sensor, sand of sizes and compositions consistent with reservoir sand and fines and also proppant that is used in our gravel pack and frac-and-pack completions. Designed into our production operations is a schedule for pulling and filtering a fluid sample to capture solid particles. Sampling is also triggered by acoustic sensor readings exceeding preset alarm levels. After a sample is procured, it is examined microscopically by the operator and an image is captured for documentation purposes, to send to an off-site expert for identification, or transmitted in real time for remote expert interpretation.
Examples of successful execution of this process will be presented, such as one high-rate gas well which set off the acoustic sensor alarms when restarting after an unplanned shut-in. The well was immediately choked back, while a sample was filtered and analyzed. The rapid identification of benign solids (inorganic salts which were a byproduct of the drill-in fluid) allowed the confidence to resume full rate production, thus preventing the loss of $150,000 cash flow per day.