bluuebunny/crossref_metadata_2025 huggingface dataset:
A Model for Borehole Oscillations
Authors: Pastusek Paul , Brackin Van
Published: December 2007

The presence of borehole rippling, spiraling, and hour-glassing have been known for many years in the drilling industry. Descriptions of these problems have become more precise with improved logging tools, yet the underlying mechanisms have not been mathematically formulated. Many directional models have been presented in the past that attempt to explain the steady state response of the bottom hole assembly, but little has been published on the non-equilibrium or dynamic response of the system.

A theoretical/analytical dynamic model is proposed to explain the conditions required for borehole oscillations to occur. This model is presented along with correlating data from laboratory and full scale field tests for a steerable motor with an 8-1/2" hole size. For different parameters the model correctly predicts the presence and absence of oscillations, the oscillation wavelength, and the effect of bit geometry on borehole oscillations. It also makes testable predictions for the effects of bit speed, penetration rate, and rock strength. From these test cases, general guidelines are presented for selecting the appropriate bit, BHA, and operating parameters for an application.
Utilization of a Tactical Grade FOG-Based Inertial Measurement Unit in Real-Time Downhole Surveying
Authors: Ledroz Adrián G. , Mintchev Martin P.
Published: December 2007

Fiber optic gyroscopes (FOG) in an inertial navigation setup have been proposed as an alternative to magnetometer-based downhole surveying. The aim of this work is to study the applicability of a tactical-grade FOG-based inertial measurement unit (IMU) as complete surveying sensor for measurement-while-drilling processes downhole. Complete navigation solution for downhole applications was tested in laboratory conditions, indicating the usefulness of FOG-based IMUs as possible surveying sensors for directional drilling.
Object-Based Global Optimization in Modeling Discrete-Fracture Network Map: A Case Study
Authors: Tran Nam H. , Chen Zhixi , Rahman Sheik S.
Published: December 2007

Modeling of fracture network is an essential step for developing naturally fractured reservoirs study. It helps to develop a best scenario for hydraulic fracture treatment, to design an optimum production method and to evaluate reservoir potential. This paper presents an integrated methodology for modeling fracture network by utilizing object modeling and global optimization. It also describes a field study to evaluate the methodology's effectiveness. Firstly, as an object-based model, each fracture is presented and treated as a discrete object, characterized by its centre location, orientation and size. Object-based modeling allows the output of spatial distribution and details of discrete fracture network. From observed data sources such as seismics, outcrops, well logs and images, etc., we characterize fracture and field attributes, including fracture density, fracture parameters' statistics. Then, we perform a statistical analysis on fracture properties to identify density functions and distribution patterns. The essential feature of this approach is the formulation of the objective function. Various variogram measurements, modified multi histograms and other statistical properties are selected, so that the objective function is able to adequately describe the representative field data. In the next step, we use global optimization (simulated annealing algorithm) to produce result fracture network, by optimizing the objective function. This network matches the field characterized fracture attributes and characteristics. A global optimization method such as simulated annealing is able to honor more data than conventional geo-statistical simulation techniques. Case study shows that the modeling methodology mapped discrete fracture network very closely to the observed fracture distribution and properties.
Seismically Driven Integrated Fracture Modeling
Authors: Shen F. , Ouenes A.
Published: December 2007

Given the importance of fractured reservoirs in the world, and the ever-increasing availability of 3D seismic data, this paper reviews existing fracture modeling approaches that use 3D seismic data. Two major approaches appear to provide efficient ways to use directly and effectively 3D seismic data. The first approach uses mostly post-stack data in an integrated computational framework where 3D seismic attributes are used along with other geologic and geomechanical information to provide reliable 3D fracture models. The second approach relies on the use of pre-stack seismic data along with other geologic and production information to provide an accurate description of the fracture density and orientation. Although these technologies are well proven and have been tested in many basins, they remain underutilized by most oil and gas companies, with the exception of a few companies that have been using them extensively to drill very successful wells.
Application of Advanced History Matching Techniques to an Integrated Field Case Study
Authors: Feraille M. , Roggero F. , Manceau E. , Hu L. Y. , Zabalza-Mezghani I. , Reis L. Costa
Published: December 2007

This paper presents an innovative integrated methodology for constraining 3-D stochastic reservoir models to well data and production history as well as a successful application to a real field case. The proposed approach allows to history match complex reservoir models in a consistent way by updating the entire simulation workflow. Advanced parameterization techniques are used to modify either the geostatistical model directly or the fluid flow simulation parameters in the same inversion loop. In a first step, the relevant inversion parameters are selected according to a sensitivity study based on the experimental design technique. In a second step, history matching is performed with the most significant parameters using an automated inversion procedure. In this step, the Gradual Deformation Method (GDM) is used to constrain the geostatistical model while respecting the global model properties. This technique may be combined with gradient based inversion methods in order to history match other deterministic parameters simultaneously.

A successful application to a real field case located offshore Brazil, named PBR, is presented. The lithofacies reservoir model was built using geostatistical simulations with the non-stationary truncated Gaussian method. The fluid flow model includes about 40 wells and 15 years of production history. The entire simulation workflow was integrated in one history matching loop in order to update the geostatistical lithofacies model and the fluid flow model simultaneously. The mismatch between simulated and real production data was quantified by the calculation of an Objective Function (OF). A sensitivity study based on the experimental design technique was performed to determine the most influential parameters within the workflow and to capture the possible reasons of the mismatch. Based on these observations, an automatic history matching was performed with the key parameters. A set of deterministic parameters, including the facies permeabilities, vertical anisotropy ratios, correlation lengths, relative permeability end points and Corey exponents was used first to improve the global match. Then, the GDM was applied to modify the geostatistical model itself. The GDM proved efficient in history matching to modify the spatial facies distribution of the geostatistical model. Moreover, the repetition of this history matching procedure with several model realizations confirmed the reduction of uncertainty on production forecasts.

Results on this real oil field case showed that this innovative approach, which combines both the experimental design technique and the GDM, enables detailed analysis of the mismatch and significantly increases the predictive quality of reservoir models, using a limited number of simulations.
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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Prediction of Sand Production Rate in Oil and Gas Reservoirs
Authors: van den Hoek P. J. , Geilikman M. B.
Published: December 2007

Most sand production prediction models to date have the capability to indicate whether initial sand production may take place somewehere during the lifetime of a reservoir. However, these models are unable to predict whether the sand production will be ‘problematic’ (e.g. in terms of erosion, plugging, well sand-up, separator fill, etc.), in particular for systems that have some tolerance towards sand production.

In order to predict whether sand production will be ‘problematic’, one needs to be able to estimate sand production volumes and rates as a function of, amongst others, bottom-hole load conditions, drawdown, and time. This paper presents a model for the prediction of sand production volumes and rates for any type of clastic oil or gas reservoir. This work builds on successful previous efforts to predict sand production rate in the Canadian heavy oil sands. The current model is a validation of the previous model and its further generalisation to sandstones of any strength (not just unconsolidated) with any reservoir fluid (not just heavy oil), and involves features such as failure of intact sand, post-failure cavity stabilisation, and non-associated viscoplasticity. The model has been calibrated to laboratory experiments.
Predicting and Managing Sand Production: A New Strategy
Authors: Palmer Ian , Vaziri Hans , Willson Stephen , Moschovidis Zissis , Cameron John , Ispas Ion
Published: December 2007

Sand prediction at BP has been developed by dividing it into three parts: (1) onset, (2) transient sanding, (3) steady-state sanding. For example, as drawdown is increased in a well in a sand-prone formation, significant sanding begins at some point (the onset), and this is followed by a transient sand burst, which may last hours or days or months. The sanding eventually declines to a background level (steady-state), in the range 1–100 pptb. We have made recent step-changes in (2) and (3), and we now have a tool that can predict sanding onset, and volumes during any stage of a well's production history, or even injection history.

The onset of sanding is predicted using a stress-based model. This model is conservative, based on a benchmarking study of field applications. One application predicts sanding in water injectors during shut-in, and recommends not using sand control. Another application explains delayed sanding in an HPHT gas reservoir, in terms of restraining forces due to capillary cohesion (i.e., the damp sand effect at the beach). The transient sanding model is a fully-coupled finite element (FE) model. The model has successfully predicted sand volumes in laboratory and field tests. With this model, we can judge whether we can manage the produced sand, from both production and injection wells. Finally, we have applied this to predict whether a well will kill itself after a blowout, due to sand in the wellbore increasing the hydrostatic pressure.

The steady-state model is an empirical model that is based upon extensive tests of sanding from cores in the laboratory. The model has been applied to predict sanding in an offshore field, and this has led to the conclusion that sand rates can be managed at surface, without sand control: a huge economic advantage. Finally, we present a case history where we use all three models to make an integrated prediction of onset, transient, and steady-state sanding, and find quite good agreement with field observations. In summary, the new three-fold strategy of sand prediction at BP has significantly increased our capability to predict sanding in production or injection wells. This quantum leap is invaluable to help decide if we can manage the sand at surface (or if downhole sand control is required); to decide if we can defer sand control until a later date (possibly increasing production as well as saving completion costs); to decide how much sand will be produced if we increase the drawdown in a sand-prone well; and even decide if we need sand control in water injectors.
Well Performance with Operating Limits under Reservoir and Completion Uncertainties
Authors: Wehunt C. D.
Published: December 2007

This paper shows how to evaluate well performance under conditions of reservoir and completion uncertainty, while also considering the impact of completion decisions and operating constraints. This topic is important because it can help to reconcile the often-large gap between theoretical, short-term deliverability, and reliable, sustainable performance.

A table of operating constraints is presented, with examples regarding application of some of the constraints. This constraint table also includes consideration for the type of surveillance that is needed to apply the constraints. Discussion within the paper shows that the most appropriate types of operating constraints are often not being used. This paper also addresses appropriate operating limits for completions with sand control installed.

Completion selection and design influence operating constraints. Examples within the paper illustrate methods to determine appropriate operating constraints. The examples also demonstrate the potential advantage of frac-packed completions or long horizontal completions with regard to preventing fines migration and increasing longevity.

To aid with probabilistic performance forecasting, the paper includes a tabulation of published skin values, including permeability data when it was available.
Improvements in Single-Phase Paraffin Deposition Modeling
Authors: Hernandez O. C. , Hensley H. , Sarica C. , Brill J. P. , Volk M. , Delle-case E.
Published: December 2007

Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient and fluid properties.

In this study, a new model for the prediction of singlephase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial wax concentration might be different from the equilibrium wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time, a process known as aging. The effect of shear stripping may also be incorporated in the prediction.

The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa University Paraffin Deposition Projects with two different oils: a black oil and a condensate. Even though some tuning is required for each oil, the new model is based on physical phenomena, reducing the empiricism of previous models.
A Novel System That Diverts Away From Water Zone: Successful Case Histories from the CNOOC Field in Java Sea - Indonesia
Authors: Soekama Robianto , Winarmo Mulad Budi , Halim Sunarto , Siddiqui M. Irfan , Dharmawan Arief , Placio Fransisco , Tibbles Raymond J.
Published: December 2007

Getting good acid diversion in high water cut wells is always a challenge. Relative permeability effects due to high water saturations will push the aqueous base treating fluid into zones with high water cut. This leaves the oil zones untreated and results in dramatic increases in post stimulation water production.. While many fluid diversion techniques exist, this paper focuses on the successful application and results of a novel Viscoelastic Surfactant (VES) based fluid used as diverter in matrix stimulation treatments performed by CNOOC in its Java Sea, Indonesia wells.
Innovative Well Completion Harnesses Deep, Hot South Texas Gas
Authors: Moe G. R. , Johnson Carl K. , Ingle Ray , Smith Robert C.
Published: December 2007

Efficient access to multiple permeable natural gas zones located in deep, over pressured, and extremely corrosive environments presents a challenge for South Texas operating companies. An innovative completion technique, featuring corrosion resistant alloy (CRA) tubulars has been effectively implemented by blending features of monobore, slim-hole, and conventional completion geometries.
A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive
Authors: Bauget F. , Egermann P. , Lenormand R.
Published: December 2007

The relative permeability curves (Kr) control the production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood) the Kr curves obtained in laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution gas drive (depressurized field, foamy oils), the experiments conducted in laboratory depend on the depletion rate and cannot be used directly for reservoir simulations.

We have developed a novel approach for calculating representative field-relative permeabilities. This new method is based on a physical model, which takes into account the various mechanisms of the process: bubble nucleation (preexisting bubbles model), phase transfer (volumic transfer function), gas displacement (bubbles flow). In our model, we have identified a very few number of "invariant" parameters that are not sensitive to depletion rate and are specific of the rock-fluids system (mainly the preexisting bubble size distribution and a factor between gas velocity and oil velocity in the dispersed phase regime). These invariant parameters are determined by history matching of one experiment at a given depletion rate.

The calibrated model is then used to generate synthetic data at any depletion rate, and especially at very low depletion rates representative of the reservoir conditions. Relative permeability are derived from these "numerical" experiments in the same way as real experiments. The calculated Kr are finally introduced in commercial reservoir simulators.

We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with a very good accuracy.

Finally, we present an example of determination of relative permeabilities at reservoir depletion rates.
Experimental and Theoretical Basis for a Wettability-Interfacial Area-Relative Permeability Relationship
Authors: Gladkikh Mikhail , Jain Vivek , Bryant Steven , Sharma Mukul
Published: December 2007

Using an interfacial tracer technique, our experiments show qualitatively different trends of total interfacial area between the wetting and non-wetting phases as a function of saturation, depending on whether the system is strongly or weakly wetted. A strongly wetted system is defined as one in which the wetting phase can spread as a thin film on the solid surface. We assess the relative contributions of fluid/fluid and fluid/solid interfaces to the total area using thermodynamic arguments. The fluid/solid contribution to area plays a crucial role in explaining the measurements.

The influence of interfacial area on relative permeability is not straightforward. Simple analysis based upon pore-level distribution of phases in a model porous medium allows quantifying the differences in the relative permeabilities for both weakly and strongly wetted systems, measured simultaneously with the interfacial area. Relative permeability correlates with fluid/solid area but not with fluid/fluid interfacial area.
Estimation of Flow Functions During Drainage Using Genetic Algorithm
Authors: Sun Xuefei , Mohanty Kishore K.
Published: December 2007

Unsteady state relative permeability experiment followed by automatic history matching has been used in the past for estimating relative permeability and capillary pressure simultaneously. The performance of the automatic history matching largely depends on the simulator, the functional form of the flow functions, and the optimization tool. Newton method, which is commonly taken as the optimization tool for the automatic history matching, may not converge to the global extremum in the presence of high non-linearity. Genetic algorithm (GA) with better global convergence property was used as the optimization tool in this work. Another advantage of GA as an optimization tool is that it requires only function evaluations for the solution searching and not Jacobian or gradient calculations as required by the Newton method. Corey model and piece-wise spline interpolation were utilized to represent the relative permeability. A new coding method in genetic algorithm was developed for piece-wise spline interpolation. In situ saturation data were collected during an unsteady state primary drainage experiment by CT-scanning. Simulation and experimental data were used to test the performance of the algorithm. Test results showed a good match between the simulation data and experimental data for low injection rate primary drainage.
Pore-to-Field Scale Modeling of WAG
Authors: Kløv T. , Øren P. E. , Stensen J. Å. , Lerdahl T. R. , Berge L. I. , Bakke S. , Boassen T. , Virnovsky G.
Published: December 2007

The paper describes an integrated pore-to-field scale modeling method of multiphase flow in porous media. Although the method is general, we demonstrate its power and versatility by modeling a WAG process in the Etive formation in a North Sea oil field. The method aims at capturing the relevant flow physics at different scales. Pore scale physics (µm-scale) is accounted for through predictive pore scale modeling of relative permeability and capillary pressure. The computed rock curves (cm-scale) are used to populate detailed geological models with a plausible spatial distribution of constitutive relations. Effective flow properties at the heterogeneous facies scale (m-scale) are determined by a steady state upscaling technique. Finally, the effective flow properties are implemented in a field scale (km-scale) simulation model. The simulation results show that the effective flow properties describe the reservoir WAG performance fairly accurately without any adjustment through history matching.
Problems of Ultra-Deep High-Temperature, High-Pressure Drilling
Authors: Shaughnessy John M. , Romo Louis A. , Soza Robert L.
Published: December 2007

Operators are looking at drilling for deeper gas reservoirs. There are a number of problems unique to ultra-deep drilling – greater than 20,000 feet. Well control is complicated by narrow margins and higher bottom hole pressures and temperatures. Application of tools that can assist in pore pressure prediction are limited by the depth, temperature and the high cost of errors. Well control problems can be spectacular. The depth pushes rig equipment loads to their design ratings. Maintenance, inspection and design of all components are more critical due to reduced margins. Wellbore tubulars are often designed for sour and corrosive production fluids. Those designs increase the pipe's weight and cause special handling requirements. Drilling tools are also limited by the depth, temperature and rock hardness. Two operators working in Texas, Louisiana and Wyoming drilling to depths of up to 25,000 feet have documented many of the industry's problems and current solutions. Understanding the problems and designing wells to reduce the risks is the first step to a cost effective drilling operation.