bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pore Pressure Prediction Using Look-Ahead Vertical Seismic Profile VSP - A Case Study from the Red Sea, Saudi Arabia
Authors: Planchart Carlos , Sierraalta Rolando , Saadan Sami , Brown John , Mengual Jean-Francois 
Published: February 2017

Abstract
A case study is presented to illustrate the successful prediction of formation pore pressure ahead-of-bit using vertical seismic profile (VSP) data acquired from the Red Sea, offshore Saudi Arabia.
Two look-ahead VSPs were collected at two intermediate depth (TD) levels. VSP data was analyzed through corridor stack and inversion to estimate the depth of potential reservoir and related interval velocity. Two strong reflections ahead of the bit were identified as having lower acoustic impedances and the deeper one was associated with a potential reservoir.
After drilling for about 4000 ft from the bottom of the first VSP, a second VSP was acquired to better image the potential reservoir and to investigate any over-pressure zones ahead of the bit in an open-hole. The second VSP clearly revealed the potential reservoir and presence of velocity reversal ahead of bit, which could be associated with an increasing pore pressure. Further drilling for few hundred feet, events such as high torque and tight hole as indicators of over-pressure were encountered. These suggested that drilling to the target reservoir could greatly increase operational risk due to over-pressure. Therefore, the decision was made to call for final TD.
The post-drill pore pressure evaluation revealed that the look-ahead pore pressure prediction was different only by a small amount from the actual measurements. This concluded that our look-ahead pore pressure prediction workflow can provide critical data for drilling engineers to call for final TD and successfully complete the well.
Feasibility of Using a Borehole Gravity Tool to Detect Fracture Systems at Reservoir Scale
Authors: Zhang Ping , Badri Mohammed , Pfutzner Harold , Abdallah Wael 
Published: February 2017

Abstract
In mature oil fields, water, steam, natural gas, and carbon dioxide are purposely injected into a reservoir to increase pore pressure on the oil, to lower the viscosity of heavy oil, and, ultimately, to increase the oil recovery factor. The placement of oil, water, and gas within the reservoir is highly dynamic and not easily predicted. Therefore, reservoir monitoring is key to improving sweep efficiency and oil recovery.
Density is an important physical property for inferring oil, water, and gas saturation in a rock. Due to the density differences of oil, water, and gas, the saturation variation of each phase will have a direct impact on the measured gravity fields. The conventional well logging tool, gamma-gamma density, has a maximum depth of investigation (DOI) of 6 to 8in in open hole and greatly reduced accuracy in cased hole. A gravimeter, in contrast, yields a density measurement with inherently large DOI, where the DOI is determined by the vertical separation between pairs of differenced measurements of the acceleration due to gravity. For example, the DOI resulting from a pair of measurements separated by 3m will be approximately 4.5m.
In this paper, we have conducted extensive simulations of using borehole gravity fields to monitor water flooding from injectors. In one scenario, we considered fracture systems within the reservoir typically identified by seismic methods; however, their impact on water flooding is not fully understood. Borehole imaging and production logging measurements clearly identify where fractures are along the borehole. However, due to their limited DOI, there is no clear picture about fractures farther from the borehole. Because the fractures are most probably filled with water and rock other than formation rock, which have a density different from that of the surrounding formation matrix, the borehole gravity field with its large DOI could provide useful information. To understand the response and the sensitivity of the borehole gravity measurements, we constructed a reservoir model with fractures of different sizes and locations within the modeled volume. From the lithology and fluid properties, density information was computed and propagated in the model. A vertical well was used as the survey location of the borehole gravity measurements. Both gravity and differential fields were calculated. The simulations were designed to address the following questions: Does the borehole gravity measurement have enough sensitivity to detect fractures within a reservoir?How far away from a borehole can fractures be accurately identified?
This paper will present our simulation results and discuss their implication for reservoir fluid-front monitoring. Although borehole gravity measurements have not been used in reservoir monitoring, this study's results demonstrate the advantage of data acquisition with large DOI, which provides a huge operational benefit and cost-effective measurements to manage oil fields.
Enhanced Discretization for Improved Stability of Thermal Simulation
Authors: Jönsthövel T. B. , Stone T. W. 
Published: February 2017

Abstract
Thermal simulation is notoriously more difficult than iso-thermal simulation due to the volatility of hydrocarbons and water in the reservoir. Moreover, thermal simulation typically involves injection of high temperature fluids relative to the reservoir and as such the simulator has to deal with sudden ‘shocks’ to the systems. The Finite Volume method with a two point flux approximation (TPFA), which is the industry standard discretization, is numerically robust for iso-thermal systems but ill-equipped to deal with shock waves of temperature and pressure propagating through the reservoir grid. Also, due to the nonlinearity of the governing partial differential equations (PDEs) and the instability of the phases introducing discontinuity in properties and their derivatives, nonlinear solvers such as Newton Raphson struggle to solve these systems. As a result thermal simulations are inherently more prone to time step reduction to reduce the nonlinearity of the problem. In turn this results in small time steps and long simulation times. In this paper we analyse the TPFA discretization for a Natural Variable Formulation and show it is failing to address rapid changes in phase states in reservoir grid cells. We present a set of modifications to the TPFA discretization based on the upstream direction that increase the robustness of the scheme without compromising physical results and may lead to dramatically improved performance.
Elastic Carbon Composite and its Use as Ultrahigh Temperature Packer Element
Authors: Xu Zhiyue , Zhao Lei , Ganguly Partha 
Published: February 2017

Abstract
Lack of reliable sealing materials with temperature rating over 600 °F (316°C) for downhole sealing and zone isolation applications in high temperature wells such as steam injection wells is a big material technology gap and concern for oil and gas industry. Traditionally, elastomers are the material chosen for downhole sealing applications. But this type of organic materials is prone to decompose when temperature approach 600°F (316°C) and even lower in wellbore fluids. Metal to metal seal may have the temperature tolerance, but lacks enough elasticity to provide reliable seal in downhole conditions. This paper will introduce a newly developed elastic carbon composite (ECC) and its use as an ultrahigh temperature packer element under extreme temperature conditions such as a steam injection well.
Tests show that the elastic carbon composite material has excellent thermal stability over 1000°F (538°C) and strong corrosion resistant to most downhole fluids, including hydrocarbons, brines, acids, etc. More importantly, it has also displayed improved mechanical strength (up to 15 KSI [103MPa]) and elasticity (6%). In addition, reasonable wear resistance observed from this carbon composite material proves it suitable for heavy oil recovery with high sand production. This new sealing material was fabricated into thermal packer elements which delivered superior sealing performance at high different pressure above 600 °F (316°C) and thermal shock cycles between 600 °F (316°C) and room temperature.
In this presentation, we will discuss the material design of this novel elastic carbon composite, the superior material properties compared to elastomeric seal materials, and the reliable performance of the ECC packer elements. The elastic carbon composite fills the technical gap of sealing material with temperature rating over 600 °F (316°C) and provides reliable solution to heavy oil recovery in the oil and gas industry.
Convex Imaging Condition for Reverse Time Migration
Authors: Yang Jiarui , Luo Yi , Ji Xu , Liu Hongwei 
Published: February 2017

Abstract
We propose a novel and computationally inexpensive imaging condition for reverse time migration (RTM), referred to as convex imaging condition. The convex imaging condition has the merit of removing two types of RTM imaging noise discovered before, i.e., the notorious low frequency noise and the primary false image, meanwhile maintaining the capability to image steeply dipping or even vertical structures. To the best of our knowledge, this advanced and important feature is not achieved by any method before, including the Hilbert transform method proposed by Faqi Liu et al. and the de-primary method (and equivalent approaches) proposed by Tong W Fei et al. and Peng Shen et al.
Integrated Approach to Investigating the Effects of Structural Fault Uncertainty on Well Test Design
Authors: Anton Adrian , Weinzierl Wolfgang , Sarac Sukru , Mahbou Eric Ndonwie 
Published: February 2017

Abstract
In a new approach to fault uncertainty, stochastic perturbation of fault interpretations is used to quantify the well test drawdown behavior of non-unique fault locations; the impact of this uncertainty is then quantified by studying the dynamic behavior of the resulting models using a numerical simulator.
An integrated approach from seismic interpretation to numerical simulation is taken to capture the uncertainty from the different disciplines involved. The structural fault location, and the uncertainty associated with it, is based on the Fresnel zone method. The impact on the dynamic response of the fault location uncertainty is quantified by analyzing the simulation results of transient well tests of a vertical well near the fault.
A pressure transient test was simulated to capture the well response for the different structural realizations. The rock and fluid models were fixed to typical values for the area. Log-log diagnostic plots for pressure differences and derivatives were calculated to assess the response of the fault locations. The tests require an investment of resources so they have to be well prepared and as effective as possible.
The results show that the fault uncertainty has a measurable impact on the dynamic behavior of the model if the transmissibility of the fault is significantly low and blocking the flow.
The novelty of the approach is the analysis of the dynamic behavior preserving the structural uncertainty of the interpretation. Well tests and dynamic simulations reveal non-negligible and quantifiable contributions to be accounted for during actual well tests. If the well tests had been designed and interpreted without the input from other disciplines, the source of uncertainty would have been less obvious and harder to quantify.
3D Image Driven Internal Multiple Elimination
Authors: Xiong Wei , Zhang Dongliang , Fei Tong W. , Yang Jiarui 
Published: February 2017

Abstract
In this paper, we present both synthetic and field data study of applying the image-driven method proposed by Antonio Pica and Laurie Delmas (2008) for internal multiple attenuation. The image-driven method includes two steps: prediction of internal multiples and subtracting of the predicted multiples from the input. The prediction step comprises of the following four procedures: 1) the recorded seismic data is muted and propagated backward-in-time to user defined fictitious depth regions; 2) secondary seismic sources are generated by multiplying the migrated image and the extrapolated wavefield by the first step; 3) the secondary sources are further propagated forward-in-time and downward-in-depth and the downward extrapolated wavefield is multiplied with the migrated image and turned into up-going reflected waves; 4) the up-going waves are further propagated to the surface and used as the predicted internal multiples, which will be adjusted and subtracted from the input by using adaptive filter.
Following the four steps described above, an internal-multiple-attenuation module is developed by using the one way wave-equation extrapolation. The method requires a migrated image and a migration velocity model as inputs. Where, the image is used as the reflectivity model, which is needed by the second and third steps mentioned above. The tests on both synthetic and field data show this method can correctly predict internal multiples, even when the migration velocity model is inaccurate. The tolerance to velocity errors stems from the fact, to certain extent, that the migrated image made from the erroneous velocity can compensate the errors presented in the velocity model in terms of making the traveltime of predicted multiples correct. Compared with the data-driven method, the main advantage of the image-driven method is that it imposes fewer requirements on the acquisition geometry.
ROP Optimization Technology for Poor Drillability Formation in Western South China Sea
Authors: Guo Yongbin , Guan Shen , Liu Zhiqin 
Published: February 2017

Abstract
According to the analysis on the geology characteristics and drilling history of Beibuwan Basin in western South China Sea, this paper went through the reasons of poor dillability, and summarized the exploration and application in rate of penetration (ROP) optimization technology in western South China Sea. Incorporating with the experiences acquired from several wells recently drilled in Beibuwan Basin, a set of ROP optimization scheme which is suitable for the poor drillability formation in this basin was introduced, meanwhile a novel polycrystalline diamond compact (PDC) bit was also developed. Therefore, a series of ROP optimization solutions for Beibuwan poor drllability formation was proposed. Field experience recorded significant optimization of ROP in poor drillability formation in Beibuwan Basin. This novel technology has played an important role in drilling cost control in western South China Sea, and can serve as reference for future drilling operation on similar formations.
New Formulation for Iron Sulfide Scale Removal
Authors: Elkatatny Salaheldin 
Published: February 2017

Abstract
Iron sulfide scale is a significant problem in the oil and gas industry and it is a common scale in sour oil and gas wells. Iron sulfide depositions have an adverse impact to production and injection operations. The precipitation of iron sulfide scale in the near-wellbore area will diminish the productivity of the production wells and loss of the injectivity of water injection wells. Iron sulfide scale has different forms based on the iron-to-sulfur ratio. Iron sulfide scale can form in soft forms that are removed easily by acids such as phyrrotite. The scale can also form in hard forms such as pyrite that is difficult to remove by acids.
The objectives of this paper are to: (1) evaluate the possibility of using different organic acids (maleic, glutamic, succinic, and gluconic), chelating agents (ethylenediaminetetraacetic acid (EDTA), and diethylenetriaminepentaacetic acid (DTPA)), or a mixture of these fluids to remove iron sulfide scale, (2) develop a new formulation of acids mixture to remove iron sulfide scale, and (3) perform a corrosion test for the developed formulation to determine the operating conditions for the developed formulation. Actual field iron scale sample was used in this study. X-ray diffraction (XRD) was used to obtain the composition of the field sample. Standard corrosion test was used to determine the corrosion rate for the developed formulation.
XRD results showed that the field sample contained pyrrhotite (55 wt%), calcite (21 wt%), pyrite (8 wt%), and troilite (6 wt%). The solubility results showed that organic acids (maleic, glutamic, succinic, and gluconic) are very weak to remove iron sulfide scale at different conditions of pH and concentrations. Chelating agents (EDTA, DTPA) at a concentration of 25 wt% and pH of 6 had a solubility of 40 g/liter of iron sulfide. The solubility results illustrated that mixing chelating agents with organic acids reduce the efficiency of removing iron scale. The developed formulation, which contains a mixture or organic and mineral acid, was able to remove 78 g/liter of iron sulfide scale at 100°C. The corrosion test results confirmed that the recommended temperature range for the developed formulation is up to 100°C with a corrosion rate of 0.014 lbm/ft2 without adding corrosion inhibitors
Thermal and Geomechanical Dynamics of High Power Electromagnetic Heating of Rocks
Authors: San-Roman-Alerigi Damian P. , Han Yanhui , Batarseh Sameeh I. 
Published: February 2017

Abstract
Perforation is an essential step in the cased completion of oil and gas wells, since it provides channels for hydrocarbon fluids to flow from the reservoir into production wells. Traditional methods for perforation cause plastic compaction, resulting in permeability loss in the rock around the perforation channels and reduction of the hydraulic conductivity in the surrounding rock formation. A feasible alternative is to use high power electromagnetic (HPEM) sources to induce a localized phase change in the rock via dielectric heating and create a perforation. This method has crucial benefits: it is contactless, waterless, improves conductivity, and reduces general damage to the rock formation. The physical dynamics that makes this possible have been extensively documented in several experimental studies, and some numerical models have been proposed to simulate the thermal mechanical coupling between the HPEM source and the rock for perforation and other stimulation operations. Yet, due to the inherent multi-scale complexity of the physics involved, a comprehensive model remains a topic of advanced research. Recently, a numerical scheme was proposed to predict the perforation geometry and production enhancements as a function of the HPEM source parameters (beam shape and energy distribution), rock properties, and stress configuration. This paper expands this workflow to investigate the effects of material heterogeneity and stress configuration on the perforation rate and the rock's morphology resulting from HPEM heating. The numerical model is based on a hybrid COMSOL-FLAC coupling. In a companion paper, this model is extended to describe the effect of long-pulsed thermal incidence and rock morphology using the thermal and continuum mechanic modules in FLAC.
Processing Frequent 4D Land Seismic Data with Buried Sensors for CO2 Monitoring
Authors: Al Ramadhan Abdullah , Hemyari Emad , Bakulin Andrey , Erickson Kevin , Smith Robert , Jervis Michael A. 
Published: February 2017

Abstract
In 2015, Saudi Aramco started a CO2 Water-Alternating-Gas (WAG) EOR pilot project in an onshore carbonate reservoir. To monitor lateral expansion of the CO2 plume, the area was instrumented with a hybrid surface/downhole permanent seismic monitoring system. This system consists of over 1000 buried seismic sensors at a depth of around 70 m, below the the depth of expected weathering layer to mitigate the time-lapse noise. Despite receiver burial, seismic data still suffers from numerous challenges including: significant amounts of high-amplitude coherent noise such as guided waves, mode conversions, and scattered energy; amplitude variations over space and time caused by source and receiver coupling; variability of wavelet shape and arrival times due to seasonal near-surface variations; and low signal-to-noise ratio (SNR). A novel processing workflow was designed for 4D processing of such data. The workflow involves five critical processes. First, the high-amplitude coherent noise is eliminated using FK-based techniques that are 4D compliant to preserve the reservoir changes between repeated seismic surveys. Second, a four-term joint surface-consistent amplitude-scaling algorithm resolves the amplitude variations. The algorithm allows both source and receiver terms to have different scalars for the same positions, but it restricts the other two terms to be position-invariant over different time-lapse surveys, as the window of analysis does not include the reservoir. This is to guarantee that the source and receiver terms are survey-dependent while the other two terms are survey-independent. Thus, the amplitude variability is linked to source and receiver positions over space and time. It also assures that the reservoir changes are not affected by changes in the overburden. Third, wavelet shape variations are addressed using a four-term joint surface-consistent spiking deconvolution algorithm that applies similar principle as the scaling algorithm. Fourth, the small variations in reflection times between different surveys (4D statics) caused by seasonal variations are corrected by a specialized surface-consistent residual statics algorithm using a common pilot derived from the base survey. Fifth, the pre-stack data is supergrouped to enhance the signal-to-noise ratio and repeatability.
The processing workflow has been applied to frequent land 3D seismic data acquired over a CO2 WAG EOR pilot project in Saudi Arabia. As a result, we obtained very repeatable seismic images that may successfully detect small CO2-related changes in a stiff carbonate reservoir.
Application of 2D NMR for Formation Testing and Sampling in Heavy Oil Formations
Authors: Idris Umar , Hursan Gabor , Eyuboglu Sami , Eid Mahmoud 
Published: February 2017

Abstract
Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling.
The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure.
We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job.
We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.