Skip Nav Destination
Filter
Filter
Filter
Filter
Filter

Search Results for
The phase-shift-plus-correction method

Update search

Filter

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

### NARROW

Peer Reviewed

Format

Subjects

Journal

Publisher

Conference Series

Date

Availability

1-20 of 3029 Search Results for

#### The phase-shift-plus-correction method

**Follow your search**

Access your saved searches in your account

Would you like to receive an alert when new items match your search?

*Close Modal*

Sort by

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the International Oil and Gas Conference and Exhibition in China, November 7–10, 2000

Paper Number: SPE-64741-MS

... iteration are used to transform

**the**residual time**shifts**to residual statics of every shot and receiver. Finally, estimated statics are combined with datum**correction**values as a final statics.**The**fulfillment course of**the****method**. Pickup first break of survey lines. In reasonable offset scope, an...
Abstract

Abstract In view of large residual static correction values after field static correction in complex areas, the field near-surface data and field static correction data are used as the initial condition of the method. The first break time is used for the basic constrain of the method. The residual time shifts can be determined in common-shot, common-receiver and common-offset domains. Thus, the global optimized residual static correction values are estimated by doing statistics of a great deal of data and by making orthogonal iteration and step-by-step approximation. After being repeatedly revised, this result plus datum correction values forms the final static correction values. This paper takes actual data as example to show the good application results of this method. Introduction In western China, the conditions of surface geology are very complex. The complex structures of the near-surface make the travel time of seismic waves distorted. It is difficult for low S/N data to stack. So the accuracy of seismic exploration results is seriously influenced by static correction problems. Field static correction methods, such as minor refraction and micro-log, can control the low frequency values well. But in complex areas, the large residual static correction values are also present after field static correction. Automatic residual static correction methods, based on reflection, only get small high-frequency static correction values. At the same time, it requires certain S/N. On the basis of classical refraction theory, the static correction methods by making an inversion near-surface model, (such as delay time method, extended generali-zed reciprocal method), require choosing true first break travel time, and must trace a common high velocity refraction layer. It is difficult to apply for whole work area in complex areas. Our 2D/3D method in this paper takes the first break time of the refraction wave as the basic constraint, and uses a global optimized algorithm on the basis of field static correction. It needs no true first break time of the refraction wave, and does not need trace a common refraction layer in the full work area, and also does not need to know the velocity and thickness of the overlying formation. It results in good effect for solving the big residual static correction problem in complex areas. Method and Theory 2D multi-domain iteration statics(2D MDIS). The basic idea of the method. On top of the high velocity layer, when the static correction values caused by low-descending velocity zone are accurately removed, the first break time should be smoothing in common shot, common receiver and common offset domains. This is the premise and foundation of the method. Our basic idea is that we first roughly adjust and then finely adjust. First, the field near-surface data and field static correction data are used as the initial condition of the method. A large quantity of first break data is used to estimate statics by taking the top of a high velocity layer as the datum. Then the residual time shifts in the common shot, common receiver and common offset domain can be known respectively because static correction errors exist. Step-by-step approximation and multiple iteration are used to transform the residual time shifts to residual statics of every shot and receiver. Finally, estimated statics are combined with datum correction values as a final statics. The fulfillment course of the method. Pickup first break of survey lines. In reasonable offset scope, an automatic and interactive manner is used to pick up a refraction first break of the high velocity layer of survey line. First break of the same off-set of survey line must trace the same phase. Crosslayer to and fro is not permitted. Estimation of initial statics. There are two ways for initial statics estimation. One way is that we use field statics files to separate out high layer statics and datum statics. The other is that we use the model method to interpolate high velocity layer statics of the survey line and datum statics on the base of field surface data. Latter static correction iteration calculation will be fulfilled by taking statics of top of the high velocity layer as initial statics. 2D multi-domain iteration statics(2D MDIS). The basic idea of the method. On top of the high velocity layer, when the static correction values caused by low-descending velocity zone are accurately removed, the first break time should be smoothing in common shot, common receiver and common offset domains. This is the premise and foundation of the method. Our basic idea is that we first roughly adjust and then finely adjust. First, the field near-surface data and field static correction data are used as the initial condition of the method. A large quantity of first break data is used to estimate statics by taking the top of a high velocity layer as the datum. Then the residual time shifts in the common shot, common receiver and common offset domain can be known respectively because static correction errors exist. Step-by-step approximation and multiple iteration are used to transform the residual time shifts to residual statics of every shot and receiver. Finally, estimated statics are combined with datum correction values as a final statics. The fulfillment course of the method. Pickup first break of survey lines. In reasonable offset scope, an automatic and interactive manner is used to pick up a refraction first break of the high velocity layer of survey line. First break of the same off-set of survey line must trace the same phase. Crosslayer to and fro is not permitted. Estimation of initial statics. There are two ways for initial statics estimation. One way is that we use field statics files to separate out high layer statics and datum statics. The other is that we use the model method to interpolate high velocity layer statics of the survey line and datum statics on the base of field surface data. Latter static correction iteration calculation will be fulfilled by taking statics of top of the high velocity layer as initial statics. The basic idea of the method. On top of the high velocity layer, when the static correction values caused by low-descending velocity zone are accurately removed, the first break time should be smoothing in common shot, common receiver and common offset domains. This is the premise and foundation of the method. Our basic idea is that we first roughly adjust and then finely adjust. First, the field near-surface data and field static correction data are used as the initial condition of the method. A large quantity of first break data is used to estimate statics by taking the top of a high velocity layer as the datum. Then the residual time shifts in the common shot, common receiver and common offset domain can be known respectively because static correction errors exist. Step-by-step approximation and multiple iteration are used to transform the residual time shifts to residual statics of every shot and receiver. Finally, estimated statics are combined with datum correction values as a final statics. The fulfillment course of the method. Pickup first break of survey lines. In reasonable offset scope, an automatic and interactive manner is used to pick up a refraction first break of the high velocity layer of survey line. First break of the same off-set of survey line must trace the same phase. Crosslayer to and fro is not permitted. Estimation of initial statics. There are two ways for initial statics estimation. One way is that we use field statics files to separate out high layer statics and datum statics. The other is that we use the model method to interpolate high velocity layer statics of the survey line and datum statics on the base of field surface data. Latter static correction iteration calculation will be fulfilled by taking statics of top of the high velocity layer as initial statics. Pickup first break of survey lines. In reasonable offset scope, an automatic and interactive manner is used to pick up a refraction first break of the high velocity layer of survey line. First break of the same off-set of survey line must trace the same phase. Crosslayer to and fro is not permitted. Estimation of initial statics. There are two ways for initial statics estimation. One way is that we use field statics files to separate out high layer statics and datum statics. The other is that we use the model method to interpolate high velocity layer statics of the survey line and datum statics on the base of field surface data. Latter static correction iteration calculation will be fulfilled by taking statics of top of the high velocity layer as initial statics.

Proceedings Papers

Publisher: Society of Exploration Geophysicists

Paper presented at the 2007 SEG Annual Meeting, September 23–28, 2007

Paper Number: SEG-2007-2295

... number of

**methods**have been proposed to address this issue, including:**phase**-**shift****plus**interpolation (PSPI), split-step and Fourier finite difference. Generally, all of these are based upon**the**idea of migrating with a number of reference velocities, and then applying some form of**correction**to improve...
Abstract

INTRODUCTION Summary We describe a phase-shift plus interpolation (PSPI) method for wave-equation migration in TTI media. To apply the PSPI methodology for anisotropy, we generate reference operators based upon phase error criteria with respect to the symmetry axis direction, and exploit correlations between parameters. The method is demonstrated on an elastic synthetic dataset generated over a thrust-belt setting, as found in the Canadian Foothills. Many hydrocarbon reservoirs, such as those in the Rocky Mountain Foothills of western Canada, lie below dipping clastic sequences characterized by tilted transverse isotropy (TTI) (Isaac and Lawton, 2004). Several authors (e.g. Vestrum et al., 1999) have shown the importance of accounting for the tilt of the symmetry axis when imaging such reservoirs using anisotropic migration, in order to correctly locate structures laterally. To realize this goal, typically Kirchhoff algorithms have been upgraded to handle TTI. Improved results can be obtained using Gaussian beam TTI migration (Zhu et al., 2005). As for isotropic migration, superior results for significantly greater effort are expected from the use of wave-equation migration methods on TTI data. In contrast to ray-tracing based methods, wave-equation migration is able to handle multi-pathing in a natural way, and is not based upon a high-frequency approximation to the wave equation. Shan and Biondi (2005) have demonstrated both 2-D and 3-D implementations of TTI wave-equation migration, using an implicit operator with explicit correction, applied in the space-frequency (x-y-f) domain. For isotropic migration, the Hale-McLellan transform (Hale, 1991) offers an efficient method to produce accurate 3-D responses (without numerical anisotropy) using an x-y-f domain operator. However, since Hale-McLellan is based on circular symmetry, this luxury is not obviously available for TTI, which lacks such symmetry. An alternative approach to wave-equation migration is based upon applying phase-shift operators in the wavenumber-frequency (k-f) domain. This choice has advantages of operator stability and accurate steep dip behavior. The main drawback, compared to x-f migration, is that lateral variations in the medium are not naturally accommodated by k-f domain operators. For isotropic migration, a number of methods have been proposed to address this issue, including: phase-shift plus interpolation (PSPI), split-step and Fourier finite difference. Generally, all of these are based upon the idea of migrating with a number of reference velocities, and then applying some form of correction to improve the fidelity for lateral velocity variations. We first outline the basic phase-shift operator, and then describe how PSPI and split-step methods can be adapted for the TTI algorithm. Split-step correction for TTI The accuracy of the operators may be enhanced by application of a split-step correction. The standard splitstep correction (Stoffa et al., 1990) can be thought of as a vertical shift to account for the difference between the reference velocity and the actual (x-dependent) velocity. The result is that near-horizontal reflectors are accurately imaged, while dipping reflectors have residual errors. In the presence of TTI, it is often assumed that the symmetry axis is normal to bedding (in fact, this assumption may beneeded to determine the axis direction

Journal Articles

Journal:
SPE Journal

Publisher: Society of Petroleum Engineers (SPE)

*SPE Journal*26 (02): 591–609.

Paper Number: SPE-204476-PA

Published: 14 April 2021

... ( Réthoré et al. 2008 ; Mohammadnejad and Khoei 2013a ). A similar framework for a single fluid

**phase**( Mohammadnejad and Khoei 2013b ) was also used to simulate**the**interaction of hydraulic fractures and**the**existing natural fractures ( Khoei et al. 2018 ). Note that in**the**above works,**the**fluid flow...
Abstract

Summary The popular cohesive zone model (CZM) that only features decreasing cohesive traction along with crack separation might not adequately represent the fracturing behavior in organic-rich shale because of increased ductility. This paper proposes a novel CZM that can realize various traction/separation laws (TSLs) by a unified formulation to better represent the increased ductility of organic-rich shale. This modified CZM was implemented in a fully coupled in-house poroelastic extended-finite-element-method (XFEM) framework that has been comprehensively verified against the latest analytical solutions. The implications of increased ductility in different forms on hydraulic fracturing were studied using the newly designed progressive parametric study. First, the shape of the TSL affects the hydraulic fracturing given the same cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed TSL. Second, the initial tensile strength, controlling when the cohesive crack starts propagating, has the greatest effect on the hydraulic fracturing among all TSL shape parameters. The effects of TSL parameters become less significant as the fracturing-fluid viscosity increases. Finally, Young's modulus among four common poroelastic parameters most significantly affects the brittleness of rock formation and hydraulic-fracture lengths. The increase in cohesive energy accompanied by the decrease of Young's modulus can greatly reduce the hydraulic-fracture length under the same injection volume.

Journal Articles

Journal:
SPE Journal

Publisher: Society of Petroleum Engineers (SPE)

*SPE Journal*23 (05): 1496–1517.

Paper Number: SPE-182639-PA

Published: 11 May 2018

... ) = [ D m 1 ( j ) , D m 2 ( j ) , … , D m N m ( j ) ] T denote

**the**parameter**shift**with D m i ( j ) = m i ( j ) − m i ( ∗ ) and D y ( j ) = [ D y 1 ( j ) , D y 2 ( j ) , … , D y...
Abstract

Summary Although it is possible to apply traditional optimization algorithms together with the randomized-maximum-likelihood (RML) method to generate multiple conditional realizations, the computation cost is high. This paper presents a novel method to enhance the global-search capability of the distributed-Gauss-Newton (DGN) optimization method and integrates it with the RML method to generate multiple realizations conditioned to production data synchronously. RML generates samples from an approximate posterior by minimizing a large ensemble of perturbed objective functions in which the observed data and prior mean values of uncertain model parameters have been perturbed with Gaussian noise. Rather than performing these minimizations in isolation using large sets of simulations to evaluate the finite-difference approximations of the gradients used to optimize each perturbed realization, we use a concurrent implementation in which simulation results are shared among different minimization tasks whenever these results are helping to converge to the global minimum of a specific minimization task. To improve sharing of results, we relax the accuracy of the finite-difference approximations for the gradients with more widely spaced simulation results. To avoid trapping in local optima, a novel method to enhance the global-search capability of the DGN algorithm is developed and integrated seamlessly with the RML formulation. In this way, we can improve the quality of RML conditional realizations that sample the approximate posterior. The proposed work flow is first validated with a toy problem and then applied to a real-field unconventional asset. Numerical results indicate that the new method is very efficient compared with traditional methods. Hundreds of data-conditioned realizations can be generated in parallel within 20 to 40 iterations. The computational cost (central-processing-unit usage) is reduced significantly compared with the traditional RML approach. The real-field case studies involve a history-matching study to generate history-matched realizations with the proposed method and an uncertainty quantification of production forecasting using those conditioned models. All conditioned models generate production forecasts that are consistent with real-production data in both the history-matching period and the blind-test period. Therefore, the new approach can enhance the confidence level of the estimated-ultimate-recovery (EUR) assessment using production-forecasting results generated from all conditional realizations, resulting in significant business impact.

Proceedings Papers

Publisher: Society of Exploration Geophysicists

Paper presented at the 2005 SEG Annual Meeting, November 6–11, 2005

Paper Number: SEG-2005-0104

... image

**the**reflector in a TI medium, it is important to design an anisotropic wavefield-extrapolation**method**. Implicit**methods**(Ristow and Ruhl, 1997),**phase**-**shift****plus**inter- polation (PSPI) (Rousseau, 1997), non-stationary**phase**-**shift**(Fer- guson and Margrave, 1998), explicit operators (Uzcategui, 1995...
Abstract

SUMMARY We develop a new 3D wavefield-extrapolation method for a transversely isotropic (TI) medium with a symmetry axis. The wavefield extrapolation is done by an implicit isotropic extrapolation operator with an explicit correction operator. The explicit correction is a 2D convolution operator in the space domain, whose coefficients are estimated by a weighted least-squares method in the Fourier domain. The extrapolation operator is stable and suitable for laterallyvarying 3D TI media. This new method can be used to extrapolate wavefields in a 3D transversely isotropic medium with a vertical symmetry axis (VTI) in tilted coordinates. We also discuss the effects of the filter length on its accuracy and shorten the filter by changing the least-squares weighting function. We present the impulse response of our algorithm and compare it with the anisotropic phase-shift method. INTRODUCTION Many rocks are anisotropic, and most sedimentary rocks can be approximated as TI media. If anisotropy is not taken into account in the migration, reflectors, especially steeply dipping reflectors, will be imaged incorrectly. To image the reflector in a TI medium, it is important to design an anisotropic wavefield-extrapolation method. Implicit methods (Ristow and Ruhl, 1997), phase-shift plus interpolation (PSPI) (Rousseau, 1997), non-stationary phase-shift (Ferguson and Margrave, 1998), explicit operators (Uzcategui, 1995; Zhang et al., 2001a,b), and reference anisotropic phase-shift with an explicit correction (Baumstein and Anderson, 2003) have been developed to extrapolate wavefields in 2D VTI, 3D VTI, or 2D tilted TI media. Explicit extrapolation operators have proved useful in isotropic wavefield extrapolation (Holberg, 1988; Blacquiere et al., 1989; Thorbecke, 1997). The dispersion relation in a tilted TI medium is very complicated, and it is very difficult to design an implicit extrapolation operator for it. However, explicit operators can still handle in the same way as isotropic media. In 3D, the circular symmetry of the isotropic or VTI media allows us to design a 1D algorithm to replace the 2D convolution operator by McClellen transformations (Hale, 1991b,a; Zhang et al., 2001b). For tilted TI media, the deviation of the symmetry axis from the vertical direction breaks that circular symmetry. As a result, a 2D convolution operator has to be designed for the wavefield extrapolation in 3D tilted TI media. Tilted coordinates (Shan and Biondi, 2004a) are used to extrapolate wavefields in a direction close to the wave propagation direction. We can use tilted coordinates to get good accuracy for high-angle energy using a less accurate operator. A VTI medium in Cartesian coordinates becomes a tilted TI medium in tilted coordinates. Thus to extrapolate wavefields in tilted coordinates in a VTI medium, we need an extrapolation operator for tilted TI media. In this paper, we extrapolate the wavefield in 3D tilted TI media using an implicit isotropic operator with an explicit anisotropic correction (Shan and Biondi, 2004b). We begin by first deriving the 3D dispersion relation in tilted TI media. Then we discuss how to design 2D antisymmetric convolution operators in the Fourier domain for tilted TI media.

Journal Articles

Journal:
SPE Journal

Publisher: Society of Petroleum Engineers (SPE)

*SPE Journal*9 (02): 186–192.

Paper Number: SPE-88364-PA

Published: 01 June 2004

... may therefore be developed to primarily provide

**correct****phase**boundaries and**phase**amounts. With that in place,**the**volume**shift**parameter can be used to**correct**for any devia- tions between**the**actual**phase**densities and those simulated with**the**EOS with no volume**correction**.**The**Peneloux volume...
Abstract

Summary Pressure/volume/temperature (PVT) data are presented for 38 reservoir fluids including fluids dominated by paraffins, heavy aromatic fluids with a significant content of C 81+ , and high-temperature/high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic [Soave-Redlich-Kwong (SRK) or Peng-Robinson (PR)] equation of state (EOS) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level, the carbon number fractions are lumped into pseudocomponents, each containing several carbon number fractions. Hydrocarbons as heavy as C 200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C 80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for T c , P c , and ? as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using a cubic EOS in the classical form. It is shown that this deficiency can be cured by introduction of a temperature-dependent volume correction term. Introduction Cubic EOS such as the SRK 1 and the PR 2 equations are widely used to simulate the phase behavior of gas and oil mixtures. The liquid densities predicted with these equations in the original form are generally too low, a deficiency that at least to some extent can been overcome by incorporating a volume shift parameter. 3 This is an additional EOS parameter affecting volumetric properties without influencing saturation points and phase compositions. To apply a cubic EOS with volume shift parameter, a critical temperature ( T c ), a critical pressure ( P c ), an acentric factor (?), and a volume shift parameter ( c ) must be assigned to each component or pseudocomponent of the actual fluid. A standard compositional analysis divides the components heavier than nC 6 into carbon number fractions. 4 Carbon number fraction C N counts the hydrocarbons with a boiling point from that of nC N-1 +0.5°C to that of nC N +0.5°C. The C 7 fraction, for example, consists of the hydrocarbons with a boiling point between 69.3 and 98.9°C (0.5°C above the boiling point of nC 6 to 0.5°C above the boiling point of nC 7 ). Each carbon number fraction contains paraffinic ( P ) and naphthenic ( N ) as well as aromatic ( A ) components, each of which will have different T c , P c , and ? values and volume shift parameters. Despite these compositional differences, it is customary to use only one set of EOS parameters to represent a whole carbon number fraction. A compositional analysis usually ends with some plus fraction as with, for example, C 10+ . The latter will contain C 10 and heavier carbon number fractions. Using high temperature gas chromatography, it is possible to analyze to C 80+ 5 or even to C 100+ , but this type of analysis is not yet standard in the oil industry. There is generally a need for a simulated split-up of the plus fraction. A generally valid characterization concept must be applicable to reservoir fluids of much varying PNA distribution. While paraffins dominate among the C 7+ components of most North Sea fluids, aromatic contents in excess of 50% are often seen in the C 7+ fraction of reservoir fluids from the Middle East, China, and Venezuela. Much exploration activity is currently directed toward deep reservoirs at HT/HP. The ability of the classical cubic EOS to represent the molecular interactions at such conditions has often been questioned. More sophisticated EOS have been proposed, some of which include terms to account for the strong repulsive forces acting at high pressures. 6–8 Fluid Compositions and Experimental Data PVT data have been investigated for a total of 48 fluid compositions. Fluids 1 through 38 are reservoir fluids, an overview of which is given in Table 1 . These fluids can be divided into: 19 "ordinary" reservoir fluids (Fluids 1 through 19) comprising reservoir oils, gas condensates, and fluids that are near critical (NC) at reservoir conditions. 9 aromatic highly dense reservoir fluids (Fluids 20 through 28). The composition of one of these fluids is shown in Table 2 . 10 HT/HP reservoir fluids. The data material further includes thermal expansion data for 10 stable oils. Oil formation volume (or Bo) factors for these oils may be seen from Table 3 . Because the data are for stable oils, the Bo factors are not influenced by gas liberation and thus provide a true picture of the thermal expansion. Either differential depletion or constant mass expansion (CME) experiments have been conducted for the oil mixtures including the heavy oils in Table 1. The PVT data for the gas condensate mixtures, the NC fluids, and the HT/HP fluids comprise CME and constant volume depletion (CVD) data.

Proceedings Papers

Publisher: Society of Exploration Geophysicists

Paper presented at the 2007 SEG Annual Meeting, September 23–28, 2007

Paper Number: SEG-2007-2290

..., transversely isotropic media with

**the****phase**-**shift**-**plus**-interpolation**method**: 67th Annual International Meeting, SEG, Expanded Abstracts, 1703 1706. Shan, G., 2006, Optimized implicit finite-difference migration for VTI media: 76th Annual International Meeting, SEG, Expanded Abstracts, 2367 2371. Shan, G., and...
Abstract

INTRODUCTION SUMMARY I develop an implicit finite-difference migration algorithm for tilted transversely isotropic(TTI) media. I approximate the dispersion relation of TTI media with a rational function series, whose coefficients are estimated by least-squares optimization. The dispersion relation of TTI media is nota symmetric function, so an odd rational function series is required in addition to the even one. These coefficients are functions of Thomsen anisotropy parameters. They are calculated and stored in a table before the wavefield extrapolation. Similar to the isotropic and VTI media, in3D a phase-correction filter is applied after the finite-difference operator to eliminate the numerical error caused by two-way splitting. I generate impulse responses for this algorithm and compare them To those generated using the phase-shift method. I also apply it to a 2D synthetic data set to verify the algorithm. Anisotropy is becoming increasingly important in seismic imaging. A vertical transversely isotropic(VTI) medium is one of the Simple stand most practical approximations for anisotropic media. However, the VTI approximation is only valid for simple geologic formations, where the bedding plane is horizontal. In an area where the sediments are steeply dipping, such as anticline structures and thrust sheets, the symmetry axis of the medium is not vertical and the medium cannot be simply approximated as VTI medium. In these area, it is usually better to consider the mastilted transversely isotropic(TTI) media. For VTI media, to image steeply dipping reflector using one-way wave equation, Shan and Biondi (2004) rotate the coordinates. Inthe new coordinates, the medium becomes TTI media. For both cases, we need to design wavefield extrapolation operators For TTI media. Compared to those of isotropic and VTI media,the dispersion relation of TTI media is much more complicated. The dispersion relation of anisotropic medium is very simple, and we have an explicit expression for it. For a VTI medium, under the assumption that the S-wave velocity equals zero, we can still derive an explicit formula For its dispersion relation. The dispersion relation of TTI media is a quartic equation, and we have to solve it numerically. Conventional implicit finite-difference methods rely on the Taylor series approximation of the explicit dispersion relation. It is very hard to derive a Taylor series for the dispersion relation of TTI media. As a result, most wavefield extrapolation algorithms for anisotropic media are based on either explicit finite-difference (Uzcategui, 1995;Zhang et al., 2001a,b;Baumstein and Anderson, 2003;ShanandBiondi, 2005;Renetal., 2005) or phase-shift plus interpolation method (Rousseau, 1997;Ferguson and Margrave, 1998). For both explicit finite-difference methods and phase-shift plus interpolation(PSPI), the complex dispersion relation does not increase the complexity of the algorithm. However both of them are very expensive; explicit finite-difference methods for TTI media require running2Dconvolutions in3DandPSPI requires extrapolating many reference wavefields. Implicit finite-difference method has been one of the most attractive methods for isotropic media. It can handle lateral variation of velocity naturally and guarantee stability. Traditional finite-difference methods, such as the 15 0 equation(Claerbout, 1971) and the 45 0 equation(Claerbout, 1985), approximate the dispersion relation by the truncation of Taylor series.

Journal Articles

Publisher: Society of Petroleum Engineers (SPE)

*SPE Reservoir Evaluation & Engineering*23 (03): 0811–0823.

Paper Number: SPE-198906-PA

Published: 13 August 2020

...

**the**timing of widespread fracture‐filling**phases**such as calcite, anhydrite, and dolomite that lack readily measurable textures or chemical signatures that track**the**relative timing. Developments in scanning electron microscopy-cathodoluminescence along with other analysis**methods**(Ukar and Laubach...
Abstract

Summary A core‐based fracture prediction method is used to illustrate a value‐of‐information (VOI) decision‐analysis protocol to inform completion decisions in tight gas sandstones. The ratio of late host‐rock cement to available pore volume (PV), or degradation index, uses petrographic observations of cement distributions in core (including sidewall cores) to predict whether nearby but unsampled fractures (widths > 0.5 to 1 mm) are sealed (nonconductive) or open (conductive). Measurements from four sandstone plays suggest that the index correctly predicts open vs. sealed fractures with an accuracy in excess of 80%. The value added is calculated using Bayesian inference in which the accuracy of the index serves as the likelihood of the prior distribution of open fractures to assess the posterior probability that data represent a useful predictor of producibility. VOI of the prediction method is more than three times the cost to acquire the data. VOI is most sensitive to play‐specific geologic and cost parameters including cost to drill, expected revenue from a successful well, cost of completion, cost of acquiring data for the index, and fracture probability distributions. The approach provides a way to value acquiring fracture data and points to a need for zone‐specific production data in tight gas sandstones.

Proceedings Papers

Publisher: NACE International

Paper presented at the CORROSION 2021, April 19–30, 2021

Paper Number: NACE-2021-16283

... calculations of

**the**aqueous**phase**. MSE-SRK model was used. It calculates**the**chemical potentials in**the**aqueous**phase**by**the**combination of**the**Helgeson-Kirkham-Flowers (HKF) equation of state for standard-state properties and**the**MSE activity coefficient model for solution nonideality.**The**Soave-Redlich-Kwong...
Abstract

Abstract Many Oil & Gas fields are sour with H 2 S partial pressures above 0.05 psi. For such situations, it is critical to employ OCTG qualified for sour service, resistant to SSC. As corrosion processes in acidic environments with dissolved H 2 S make the testing solution to drift, some standardized test solutions are highly buffered with the acid-base couple acetic acid / acetate. Another method for limiting the pH drift consists by frequent additions of strong acid during the test. The objective of this work is to compare NACE TM0177 Solution B, EFC 16 solution with and without pH adjustment and HLP solution. Thermodynamic calculations for predicting the saturation pH, hydrogen permeation tests, corrosion rates and fine characterizations of iron sulfide scales were performed for being correlated to SSC test results and for understanding the impact on the hydrogen uptake and the protectiveness of corrosion products. Introduction Enhanced metallurgies must be selected for OCTG for preventing catastrophic failures due to SSC in sour gas and oil wells. According to the Annex B of the NACE MR0175/ISO 15156-2 document, 1 a material is identified as SSC resistant when it has a threshold stress higher than 80% AYS with uniaxial tensile test in the sour brine NACE TM0177 Solution A saturated by 1 bar H 2 S. 2 Since a couple of decades, the increase of the mechanical properties of OCTG was motivated to access hydrocarbons in deeper reservoirs. For example, 125 ksi SMYS materials resistant to SSC were developed but for limited range of range of pH and P H2S , so-called fit-for-purpose (FFP) environments. 3-5 NACE TM0177 Solution A, as defined in the 70's, is acknowledged as a very severe sour Quality Control (QC) condition. Consequently, the pH drift during the corrosion test and resulting from corrosion processes is not a matter of concern. On the contrary, for materials qualified in FFP environments, it is important to keep constant the sour severity level by limiting the pH drift as much as possible. Several strategies are employed to fulfill that objective; either by increasing the buffer capacity of the test solution, which is predominantly done thanks to the acid-base couple acetic acid/acetate, 6 or by the regular addition of a strong acid during the test duration. 7 Up to now, few information is available on the impact of pH control and more globally of the test solution composition on SSC. Even though regions of environmental severity for SSC in NACE MR0175 / ISO 15156-2 are defined only through pH and P H2S , it is now well established that the gas composition modifies the risk of SSC occurrence by affecting H 2 S gas fugacity and consequently aqueous H 2 S activity. This fact has motivated the addition of a technical circular inside ISO 15156 document. 8 Some works provided evidences that the composition of the solution itself is susceptible to impact directly the risk of SSC on low alloyed steels. Case et al. observed an increase of the threshold stress intensity factor on C110 when increasing salt concentration, which impacts the aqueous H 2 S activity and also likely adsorbed H 2 S coverage on steel surface. 9 Duvall Deffo Ayagou and co-authors investigated the influence of the acetic acid / acetate buffering on the corrosion rate and the hydrogen uptake of X65 linepipe. 10 Corrosion rates markedly increase with the buffer capacity of the test solution and hydrogen permeation fluxes as well.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 29–October 2, 2002

Paper Number: SPE-77385-MS

...

**phase**compositions. To apply a cubic equation of state with volume**shift**parameter, a critical temperature (Tc), a critical pressure (Pc), an acentric factor (w) and a volume**shift**parameter (c) must be assigned to each component or pseudo- component of**the**actual fluid. A standard compositional...
Abstract

Abstract PVT data are presented for 38 reservoir fluids counting fluids dominated by paraffins, heavy aromatic fluids with a significant content of C 81+ and high-temperature-high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic equation of state (SRK or PR) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level the carbon number fractions are lumped into pseudo-components, each containing several carbon number fractions. Hydrocarbons as heavy as C 200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C 80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for T c , P c and ? as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using cubic equations of state in the classical form. It is shown that this deficiency can be cured by introduction of a temperature dependent volume correction term. Introduction Cubic equations of state (EOS) like the Soave-Redlich-Kwong 1 and the Peng-Robinson 2 equations are widely used to simulate the phase behavior of gas and oil mixtures. The liquid densities predicted with these equations in the original form are generally somewhat too low, a deficiency that at least to some extent can been overcome by incorporating a volume shift parameter 3 . This is an additional EOS parameter affecting volumetric properties without influencing saturation points and phase compositions. To apply a cubic equation of state with volume shift parameter, a critical temperature (T c ), a critical pressure (P c ), an acentric factor (?) and a volume shift parameter (c) must be assigned to each component or pseudo-component of the actual fluid. A standard compositional analysis divides the components heavier than nC 6 into carbon number fractions 4 . Carbon number fraction C N counts the hydrocarbons with a boiling point from that of nC N-1 + 0.5 °C to that of nC N + 0.5 °C. The C 7 fraction for example consists of the hydrocarbons with a boiling point between 69.3 °C and 98.9 °C (0.5 °C above the boiling point of nC 6 to 0.5 °C above the boiling point of nC 7 ). Each carbon number fraction contains paraffinic (P), naphthenic (N) as well as aromatic (A) components, each of which have different T c 's, P c s, ?'s and volume shift parameters. Despite these compositional differences it is customary to use only one set of EOS parameters to represent a whole carbon number fraction. A compositional analysis usually ends with some plus fraction as for example C 10+ . The latter will contain C 10 and heavier carbon number fractions. Using high temperature gas chromatography it is possible to analyze to C 80+ 5 or even to C 100+ , but this type of analysis is not yet standard in the oil industry. There is generally a need for a simulated split-up of the plus fraction. A generally valid characterization concept must be applicable to reservoir fluids of much varying PNA distribution. While paraffins dominate among the C 7+ components of most North Sea fluids, aromatic contents in excess of 50% are often seen in the C 7+ fraction of reservoir fluids from the Middle East, China and Venezuela. Much exploration activity is currently directed towards deep reservoirs at high temperature and high pressure. The ability of the classical cubic equations of state to represent the molecular interactions at such conditions has often been questioned. More sophisticated equations of state have been proposed, some of which include terms to account for the strong repulsive forces acting at high pressures 6–8 .

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 30–October 2, 2019

Paper Number: SPE-196119-MS

... additional variables are assigned to these blocks.

**The**adjoint variables associated with pressure**shifts**in**the**additional coarse blocks are assumed to resemble an average of**the**adjoint variables associated with pressure**shifts**in**the**sub-blocks, since pressure is an intensive property.**The**adjoint...
Abstract

We develop a novel ensemble model-maturation method that is based on the Randomized Maximum Likelihood (RML) technique and adjoint-based computation of objective function gradients. The new approach is especially relevant for rich data sets with time-lapse information content. The inversion method that solves the model-maturation problem takes advantage of the adjoint-based computation of objective function gradients for a very large number of model parameters at the cost of a forward and a backward (adjoint) simulation. The inversion algorithm calibrates model parameters to arbitrary types of production data including time-lapse reservoir-pressure traces by use of a weighted and regularized objective function. We have also developed a new and effective multigrid preconditioning protocol for accelerated iterative linear solutions of the adjoint-simulation step for models with multiple levels of local grid refinement. The protocol is based on a geometric multigrid (GMG) preconditioning technique. Within the model-maturation workflow, a machine-learning technique is applied to establish links between the mesh-based inversion results (e.g., permeability-multiplier fields) and geologic modeling parameters inside a static model (e.g., object dimensions, etc.). Our workflow integrates the learnings from inversion back into the static model, and thereby, ensures the geologic consistency of the static model while improving the quality of ensuing dynamic model in terms of honoring production and time-lapse data, and reducing forecast uncertainty. This use of machine learning to post-process the model-maturation outcome effectively converts the conventional continuous-parameter history-matching result into a discrete tomographic inversion result constrained to geological rules encoded in training images. We demonstrate the practical utilization of the adjoint-based model-maturation method on a large time-lapse reservoir-pressure data set using an ensemble of full-field models from a reservoir case study. The model-maturation technique effectively identifies the permeability modification zones that are consistent with alternative geological interpretations and proposes updates to the static model. Upon these updates, the model not only agrees better with the time-lapse reservoir-pressure data but also better honors the tubing-head pressure as well as production logging data. We also provide computational performance indicators that demonstrate the accelerated convergence characteristics of the new iterative linear solver for adjoint equations.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Reservoir Characterisation and Simulation Conference and Exhibition, September 17–19, 2019

Paper Number: SPE-196705-MS

... is derived from

**the**FWL depth. With**the**tilted FWL,**the**FWL depth value varies for every grid cell. This would mean that there is a vertical**shift**in**the**saturation height function for every grid cell with a different FWL depth value. If**the**traditional saturation calculation**methods**are used in**the**...
Abstract

Hydrocarbon in place volumes are often inaccurate as a result of poor representation of the reservoir structure (by means of a 3D grid), that in combination with the use of traditional saturation calculation methods, lead to erroneous hydrocarbon volumes and poor investment decisions. Traditionally a reservoir model is represented with a 3D grid, in a complex setting such as fault intersections and stacked reservoirs. A corner point grid is often used, which has limitations to represent this complexity. Further, the hydrocarbon saturations are then derived on a cell by cell basis on that 3D grid using simple averaging techniques of saturation height functions. The poor structure representation on the pillar grid in addition to the simplistic averaging methods lead to inaccuracies of the in place volumes especially where a prominent transition zone is present. This paper presents new advanced saturation averaging methods (volume and height weighted) using saturation height functions on 3D grids. The new advanced saturation averaging methods are used on different reservoir models to compare the saturation distribution and volumetric differences against the traditional saturation calculation methods. A 4-way dip closure reservoir model with a tilted free water level (typical example of a carbonate reservoir in the Middle East), and a faulted S-grid model of the F3-FA field (North Sea) are used. For the 4-way dip closure reservoir model, when comparing the advanced ‘volume weighted’ and traditional ‘by center of the part of the cell’ saturation averaging methods, a significant difference in the water saturations is observed which leads to about 5% difference in the calculation of in place hydrocarbon volumes. Further, it is observed that changing the thickness and orientation of the 3D grid cells can result in even larger differences of 5-10%. The faulted F3 model shows that the difference between the hydrocarbon saturation values is largest where it matters most, that is, around the fluid contacts and in the transition zone. The new advanced saturation averaging methods give accurate hydrocarbon saturations irrespective of the size or complexity of the 3D grid and without any discretization effects.

Proceedings Papers

Paper presented at the International Petroleum Technology Conference, March 23–April 1, 2021

Paper Number: IPTC-21491-MS

.... Condensate is defined as a low-density, high-API gravity liquid hydrocarbon

**phase**that occurs in association with natural gas ( Ayub & Ramadan, 2019 ). Figure 1 below shows a typical**phase**envelope of**the**condensate. Condensate is formed when**the**reservoir pressure falls below**the**dewpoint pressure...
Abstract

Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO 2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO 2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO 2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO 2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 24–26, 2018

Paper Number: SPE-191458-MS

... alignment between

**the**tool internals and**the**side port connection on**the**sub. A critical time during**the**operational sequence occurs when**the**diverter line (flowline that installs into**the**sub side port) is installed, and fluid is flowing through it. During this**phase**of operation, it is important to...
Abstract

Continuous circulation technology is used to maintain constant circulation of drilling fluid in a well by enabling the rig pumps to remain on during all steps of the drillpipe connection process. Continuous circulation is a managed pressure drilling (MPD) technique; it improves drilling success for difficult high-pressure high-temperature (HPHT), narrow pore pressure/fracture gradient, and extended reach horizontal wells. Traditionally, a continuous circulation system relies on a manifold connected into the rig standpipe, which diverts flow to and from the topdrive to a side port on a sub that is threaded into the top of each drilling stand. Historically, this side port flowline is connected manually by an operator, within the rig floor red zone, in a single barrier pressure environment. To enhance safety by removing exposure to any single barrier pressure applications, a new system was developed that automates and enhances the current manual process. The automated continuous circulation system includes a connection tool that is mounted on a manipulator arm; after it is delivered to the drillstring and clamped, it will use a human machine interface (HMI) to automatically and remotely remove a threaded side port safety cap, connect the side port flowline, and control the manifold flow diversion process. The system is controlled at the HMI by an advanced software system that is capable of functioning autonomously, with operator verification steps. Internal robotic mechanisms drive the system to perform the exact steps as a human without requiring modifications to the proven continuous ciruclation sub design, all while providing instantaneous feedback to the operator located at the remote HMI. A prototype tool was assembled and successfully tested in November 2016 in the Val D'Agri oilfield region in southern Italy. With a rapid technical development cycle of less than one year in a down market, a commercial tool was developed and deployed, including the implementation of all lessons learned. This system is the first in the industry to provide threaded engagement of the side port flowline, and a successful undermount delivery arm. This paper presents results from more than 1,000 diversion connections in both laboratory and field environments. With a 10-year track history of the manual system, the automated system enables the operator to improve upon proven technology to safely deploy continuous circulation capabilities in offshoreapplications, from fixed platforms to floaters, in areas with strict industry certification regulations, personnel in red zone limitations, and double pressure barrier requirements. The system reduces overall added connection time from typical manual systems, increases safety, and maintains the benefits of continuous circulation to reduce nonproductive time (NPT) and total drilling days.

Proceedings Papers

The Nguyen Dac, Michael Sanders, Tuan Nguyen Ngo Anh, Pascal Millot, Sadu-ur Rehman, Katsuko Suzuki, Michael Lawson, Foo Say Jeow, Khanh Tran Van

Paper presented at the International Petroleum Technology Conference, December 6–9, 2015

Paper Number: IPTC-18305-MS

... multiples can have good resolution comparable to

**the**surface seismic image, with better signal to noise ratio especially for**the**shallower reflectors.**The**VSP data is true amplitude, zero-**phase**, and perfectly tied in depth and in time. In very deep water,**the**seafloor-sea surface multiple is completely...
Abstract

The Vertical Seismic Profile (VSP) technique is routinely used to create seismic images near the wellbore; traditionally, only the up-going wavefield is used to image the subsurface below the receivers. The standard VSP technique does not provide seismic image information above the well trajectory. The objective of this study was to produce a seismic image above the top receiver depth up to the seafloor by using the downgoing multiples recorded in the VSP data for a more complete seismic-to-well tie. In VSP acquisition, the seismic source is positioned below Mean Sea Level and deployed above a downhole receiver. The source signal is recorded by a downhole receiver that is moved to cover a large number of depth levels in the well. The upgoing and downgoing arrivals are separated during processing; the up-going wavefield is used for subsurface illumination, whereas the downgoing wavefield and multiples are normally excluded from the processing. The standard VSP technique using the VSP upgoing wavefield gives a seismic image along the range of receiver depths and below the well trajectory. However, a VSP image can also be obtained from the downgoing multiple sequences in deep water. The processing of sea surface multiple is used mainly to obtain a VSP image of formations above the top receiver depth; such an image is unattainable with the standard VSP technique. Our results show that illumination coverage increases significantly when using multiples versus primaries. In addition, reflectors above the shallowest receiver can be imaged by multiples, including the seabed itself. This can be useful for shallow hazard identification for sidetracks or to avoid the expense of infill nodal seismic below the rig ( Farmani et al., 2012 ). We also show that the image obtained from the VSP multiples can have good resolution comparable to the surface seismic image, with better signal to noise ratio especially for the shallower reflectors. The VSP data is true amplitude, zero-phase, and perfectly tied in depth and in time. In very deep water, the seafloor-sea surface multiple is completely separated in time from the air gun signature and is out of the time range of the conventional processing and interpretation steps. By using the deepwater surface-related VSP multiples and the mirror-imaging technique, the VSP image was extended successfully above the well trajectory upward to the seafloor and shows a good correlation with the surface seismic section ( Marques et al., 2011 ). We present a case study using the sea surface downgoing multiples for this unconventional VSP imaging technique.

Journal Articles

Sigurd S. Pettersen, Carl F. Rehn, Jose J. Garcia, Stein O. Erikstad, Per O. Brett, Bjørn E. Asbjørnslett, Adam M. Ross, Donna H. Rhodes

*Journal of Ship Production and Design*34 (01): 72–83.

Paper Number: SNAME-JSPD-2018-34-1-72

Published: 01 February 2018

... value robustness. 4. Case study

**The**case study centers on**the**design of an OCV, following**the**RSC**method**.**The**information gathering**phase**was in- formed by interviews with decision-makers from a real ship design project, and a retrospective Accelerated Business De- velopment process. This process is...
Abstract

In this paper, we address difficulties in ill-structured ship design problems. We focus on issues related to evaluation of commercial system performance, involving perceptions of value, risk, and time, to better understand trade-offs at the early design stages. Further, this paper presents a two-stakeholder offshore ship design problem. The Responsive Systems Comparison (RSC) method is applied to the case to untangle complexity, and to address how one can structure the problem of handling future contextual uncertainty to ensure value robustness. Focus is on alignment of business strategies of the two stakeholders with design decisions through exploration and evaluation of the design space. Uncertainties potentially jeopardizing the value propositions are explicitly considered using epoch-era analysis. The case study demonstrates the usefulness of the RSC method for structuring ill-structured design problems. 1. Introduction In a competitive maritime industry, there is a need to design, develop, and deliver systems able to sustain value throughout a multi-decade lifetime. However, design of ocean engineering systems remains a difficult task, mainly due to the complexity and uncertainty governing these systems and their sociotechnical contexts. Even a clear definition of what is a better ship is ambiguous (Ulstein & Brett 2015)—it all depends. Understanding the relation between business strategies and corresponding marine design decisions, is not straight forward, and the ship design task could be considered a wicked problem (Andrews 2012), or an ill-structured problem (Simon 1973). An ill-structured problem lacks a specified beginning and goal states, and the relation between these are unknown. More information must be gathered to enrich the problem definition and take informed decisions. A differentiation can hence be made between the problem of defining the problem to solve, and the problem of solving this problem. In this paper, we stress the importance of understanding both of these aspects when it comes to design of complex systems.

Proceedings Papers

Cenk Temizel, Celal Hakan Canbaz, Onder Saracoglu, Dike Putra, Ali Baser, Tomi Erfando, Shanker Krishna, Luigi Saputelli

Paper presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, July 20–22, 2020

Paper Number: URTEC-2020-2878-MS

... decisions. During

**the**initial**phase**of exploration, an appraisal of hydrocarbons in place and**the**recoverable resources is very crucial in determining whether to advance to field development. During**the**initial**phase**of development, surface facilities and sales contracts are quantified on**the**basis of...
Abstract

Predicting EUR in unconventional tight-shale reservoirs with prolonged transient behavior is a challenging task. Most methods used in predicting such long-term behavior have shown certain limitations. However, long short-term memory (LSTM) – an artificial recurrent neural network (RNN) architecture used in deep learning – has proven to be well-suited to classifying, processing, and making predictions based on time series data with lags of unknown duration between important events. This study compares LSTM and reservoir simulation forecasts. Available unconventional tight-shale reservoir data is analyzed by LSTM and predictions obtained. A reservoir simulation model based on the same data is used to compare the LSTM forecast with results from a physics-based model. In the LSTM forecasting, any operational interferences to the well are taken into account to make sure the machine learning model is not impacted by interferences that do not reflect the actual physics of the production mechanism on the behavior of the well. The forecasts from the LSTM machine learning model and the physics-based reservoir simulation model are compared. The LSTM model shows a good level of accuracy in predicting long-term unconventional tight-shale reservoir behavior using the physics-based reservoir simulation model as a benchmark. An analysis of the comparison shows that the LSTM machine learning model provides robust predictions with its long-term forecasting capability. This allows for better data-driven forecasting of EUR in unconventional tight-shale reservoirs. A detailed analysis is done using the forecast results from LSTM and the reservoir simulation model, and the key drivers of the EUR response are evaluated and outlined. Deep learning applications are limited in the oil and gas industry. However, it has key advantages over other conventional machine learning methods; especially where relationships are in time and space and not very clear to the modeler. This study provides a detailed insight into deep learning applications in the oil and gas industry by using LSTM for long-term behavior prediction in unconventional shale reservoirs.

Proceedings Papers

Publisher: Society of Exploration Geophysicists

Paper presented at the 2018 SEG International Exposition and Annual Meeting, October 14–19, 2018

Paper Number: SEG-2018-2998399

... arrow points out scattering data that will be removed (replaced with zeros).

**The**black arrow indicates removing of negative polarity, improving data con- sistency. These noises cause diffracted artifacts in stacking.**The**red arrow shows**the**direction of**shifting**smearing sig- nals downward to**the**new...
Abstract

ABSTRACT Poynting vector based reverse time migration () can migrate seismic data into angle-domain common-image gathers (). The quality of common-image-gather is related to the used migration velocity. However, in the seismic data processing, we usually cannot obtain a very accurate depth migration velocity. The difference between the true depth velocity and estimated migration velocity would introduce image artifacts, which are often observed as non-flat events in the . These non-flat events will degrade the final image that is linearly stacked from all angles. To mitigate such image artifacts caused by the inaccurate migration velocity, we can use both quantitative and qualitative methods to optimize the stacking. The quantitative method uses a numerical method to achieve an optimal velocity model for migration. However, there is residual moveout error still left in the gathers. Instead, we propose a qualitative method to assure geologically meaningful result, so-called segmentation method using Moore neighborhood algorithm, which can decompose events in the into isolated signal groups. From this sequestered image domain, signals can manifest easier because of dealing only local signals that do not interfere with adjacent ones. We can automatically align concave events and focus stretching amplitudes at far angles. Additionally, we do not need cross-correlation to measure the moveout of non-flat events. Consequently, we can avoid the mismatching among the events at different depths. We test our proposed method by one numerical dataset. The numerical results show that the can correct the non-flat events in the from small angle to large angle. Compared with the tradition with Laplace filtering and small angle stacking, our new method can produce a superior migration image with fewer artifacts. In practice, this proposed method can reduce the requirement of migration velocity accuracy in the depth velocity building and provide a first-look of image. Presentation Date: Tuesday, October 16, 2018 Start Time: 1:50:00 PM Location: Poster Station 20 Presentation Type: Poster

Proceedings Papers

Publisher: Offshore Technology Conference

Paper presented at the OTC Brasil, October 24–26, 2017

Paper Number: OTC-28137-MS

... via a flexible riser, which connects into

**the**Petrobras gas export system.**The**bellmouth change-out operations consisted of replacing**the**bellmouths of each of**the**8 production risers.**The**paper will focus on engineering design and offshore operation**phases**to implement**the**bellmouth change-out in a...
Abstract

Offshore constructions costs can be very high when the operation requires the use of additional vessels and support tugs. This was the case in 2016, when some of the riser bellmouths needed to be replaced on one FPSO located offshore Brazil. The initial bellmouth change-out plan included an installation vessel plus support tugs to hold the turret moored FPSO in position. As a result of the current cost constraints in the offshore industry, it was necessary to challenge the conventional way of working and to re-evaluate the construction methodology. This paper presents the methodology used on the FPSO bellmouth change-out, where all operations were conducted from the FPSO, without the need for the installation vessel or support tugs. The FPSO for this case study is located in the Campos Basin deepwater, in 1485m water depth, and approximately 70 kilometers east of Victoria, Brazil. The FPSO started production at its current location in May 2010. The unit has a maximum oil production capacity of 100,000 bopd, and a gas processing capacity of 70 mmscfd. Oil is stored onboard and offloaded through a tandem moored shuttle tanker. The gas is compressed and exported from the FPSO via a flexible riser, which connects into the Petrobras gas export system. The bellmouth change-out operations consisted of replacing the bellmouths of each of the 8 production risers. The paper will focus on engineering design and offshore operation phases to implement the bellmouth change-out in a safe, cost effective manner.

Proceedings Papers

Paper presented at the The 27th International Ocean and Polar Engineering Conference, June 25–30, 2017

Paper Number: ISOPE-I-17-043

... research could be focused on creating a two-

**phase**model for MPS**method**. b) In**the**two-dimensional simulation,**the**wave-induced forces and pressure distribution on**the**bottom become more complicated owing to**the**deformation of**the**plate.**The**numerical result shows that it takes more time for water to...
Abstract

ABSTRACT That the solitary wave impacting onto the horizontal plate above the surface is investigated numerically using Moving Particle Semi-Implicit and finite element coupled method (MPS-FEM) in this paper. The wave-induced force and pressure distribution on the bottom of the plate are the major concerns in this research. Case of the rigid plate in three-dimensional situations is initially considered. The comparisons between the calculated vertical and horizontal force and the available experimental results show fair agreement, which indicate that the solver can successfully predict the wave-induced forces. The simulation of two-dimensional solitary wave impacting onto flexible plate is finally conducted. Results from cases of the flexible and the rigid plate are compared to investigate the effects of flexibility on the wave-plate interaction. INTRODUCTION The model of wave interacting with horizontal plate is commonly observed in the offshore and coastal engineering. For example, a very large floating structure (VLFS) with its horizontal size much greater than the vertical size is usually treated as thin plate floating in the ocean. While encountering severe wave, it could produce considerable deformation which will exert a great influence on the flow field nearby, making the problem more complex. Apart from VLFS, offshore drilling platform, coastal bridge and wave-breaker are among the structures suffering from the impact of the wave. To ensure the safety of these structures, the fluid-structure interaction (FSI) analysis is sometimes indispensable. The interaction between wave and plate is an issue widely investigated by the researchers. In the early times, scholars such as Kaplan et al. (1995) adopted an empirical method to study the wave-plate interaction problem. The wave-induced forces are decomposed into the components of slamming force, drag force, inertia force and buoyancy force, which are determined according to the results of physical model tests. Allsop et al. (2006) tried to divide the forces into the components of slowly varying load and the short-duration impact load in order to analyze the jetties/piers exposed to large waves. Some scholars also managed to calculate the time-dependent loads on a plate with numerical methods. Seiffert et al. (2014) obtained the wave-induced force on a flat plate under the solitary wave with various amplitudes, water depths and vertical positions using the open source CFD software - OpenFOAM. Hayatdavoodi et al. (2015) adopted the Green-Naghdi theory to investigate the interaction between solitary and cnoidal waves and submerged horizontal plate. The nonlinear forces and overturning moment are obtained using the Level I Green-Naghdi nonlinear-wave equations.

Advertisement