bluuebunny/crossref_metadata_2025 huggingface dataset:
Positive Influence of Project Risk Management on Project's Schedule, Quality, and Cost Target
Authors: Bopalia Vinod
Published: February 2017

Risk is theoretically described as any potential deviation from the predefined target with its defined specifications. It is normally linked to terms such as issues, uncertainty, unknown etc. With dynamic situations involving unknown factors which can have pleasant or unpleasant, and mostly unforeseen and unpredictable consequences.

Project risk management is the art and science of identifying, assigning and responding accordingly to the risk throughout the life of a project and in the best interests of meeting project objectives and goals.

Risk management is often overlooked on projects, but it can help improve project success by helping select good projects, determining project scope and developing realistic project targets.
Gravel Pack a 500 ft High Permeability Cased Hole Well: Case Study, Gulf of Suez, Egypt
Authors: Khaled Omar , El Maghraby Omar , Sobhy Ahmed , Okasha Mohamed , Arafa Mahmoud , Hashem Sameh
Published: February 2017

Sand production has always been a challenge for oil operators worldwide. Several parameters can lead to sand production, including poor cementing material in the reservoir, high production rates, and high drawdown applied to an unstable zone. The subject field consists of 105 wells; 90 of these wells are oil producing wells, 11 are water injection wells, two are dump flood wells, and two are water source wells. The primary challenge was to perform a gravel pack job on a high permeability water source well to deliver a planned rate of 25,000 bwpd.

A study for the formation, the area, and the history of gravel packing in the operator fields was made to provide the optimum solution for the target well. The well was categorized as a critical well because of the various challenges and because of its importance to the operator in supplying the field with the injection water, which was down for months. The completion specifications, sizes, and the pumping techniques were agreed upon with the operator and the critical well review team. The well suffered from high losses resulting from the high permeability and long interval. The fluid losses had to be controlled before running in with the completion equipment and pumping the gravel pack treatment to avoid premature screenout.

After perforating the pay zone, the well, as expected, suffered from high losses. These losses were controlled by pumping several non-damaging fluid loss pills until the losses were suitable for running the gravel pack assembly in the hole. The treatment was pumped in alternating stages of clean fluid and slurry fluid to aid in the displacement of the proppant in the annular space and to minimize the risk of bridging.

Premium screens (6-5/8 in. with 175 micron filter) were used along with a 40/60 proppant. A 5-in. wash pipe was used to force the majority of the fluid in the slurry to remain in the casing/screen annulus to maximize sand transport, rather than leaking off through the screen and into the screen base pipe/wash pipe annulus.

The treatment was successfully pumped, covering the 500 ft of screens and leaving excess volume of sand covering the blanks. The well was completed with an electrical submersible pump (ESP) and is producing 11,500 bwpd with no reported issues.

The injection in the field is now online after being down for five months as a result of shutting down the well.
Feasibility of Predicting Long-Term Shale Gas Production and EURs Based on Early-Time Data
Authors: Balan H. Onur , Gupta Anuj , Georgi Daniel T. , Bartko Kirk
Published: February 2017

A detailed sensitivity analyses was conducted on an analog simulation model of a hydraulically fractured shale gas well to assess the effects of various controlling parameters on gas rates throughout the production life. Differentiating operational parameters from reservoir properties facilitates high grading shale gas exploration play evaluation and provides guidance to optimize gas production, and manage uncertainties associated with reservoir properties for predictive forecasting.

The sensitivity analyses suggest that early-time gas rates are primarily dominated by the characteristics of stimulated rock volume (SRV), while late-time rates are controlled by reservoir properties. The learnings from sensitivity analyses were applied to predict production rates and estimated ultimate recovery (EUR) for a shale gas well in the KSA with flowback data. Early-time wellhead pressure data is very likely controlled by the effect of transient liquid loading and wellbore dynamics, and, as such, may mask the actual reservoir pressure response. While history matching the flow-back period may reduce the uncertainties associated with the quantification of SRV, wellbore dynamics, and initialization, large uncertainties in the estimates of reservoir properties remain the same. This reduces the confidence in predicting long-term production. Therefore, accurate measurement of reservoir properties before massive hydraulic fracturing, independent of history matching the early-time response, is critical for obtaining reliable predictions of gas rates and EUR.
Toward an Integrated and Realistic Interpretation of Continuous 4D Seismic Data for a CO2 EOR and Sequestration Project
Authors: Nivlet Philippe , Smith Robert , Jervis Michael A. , Bakulin Andrey
Published: February 2017

In 2015, Saudi Aramco commenced its first carbon capture and sequestration project, with carbon dioxide (CO2) injected into a small area of a carbonate reservoir located in the Eastern Province of Saudi Arabia. To monitor the expansion of the CO2 plume, continuous 4D seismic data is being recorded at an average rate of one survey per month. The interpretability of data requires: (1) a high degree of repeatability, which has been achieved through dedicated acquisition and processing, (2) sufficient sensitivity of seismic data to injected CO2, (3) accurate characterization of reservoir heterogeneity, and (4) a fit-for-purpose workflow to interpret time-lapse seismic images. This paper focuses on the last three points.

First, a rock physics model (RPM) is calibrated from available well data (well logs, fluid analysis), showing that CO2 injection causes a drop in both acoustic impedance and Poisson's ratio of 6% at the well log scale, leading to moderate seismic data sensitivity, and therefore, a priori challenging interpretation. Second, the RPM allows estimating changes in elastic parameters corresponding the CO2 saturation variations predicted at different calendar times by the history matched reservoir model. Synthetic seismic data is modeled, to which we add realistic seismic noise, directly derived from seismic monitoring data. A multivariate statistical model between 4D amplitude maps and CO2 concentration is calibrated. Finally, this model is used to produce maps of CO2 concentration as predicted by the seismic data. Uncertainty is propagated throughout this approach, which allows us to use statistical methods to highlight regions where a 4D signal is strong enough to produce a detectable response.

Besides providing an integrated interpretation of 4D seismic, the proposed approach also quantifies the impact of seismic data uncertainty, providing a more realistic, and therefore, more useful interpretation.
A New Insight on Simulating Ahmadi Fractured Reservoir in Bahrain Field
Authors: AL-Muftah Ali E. , Barni Sajeda
Published: February 2017

Ahmadi is a shallow carbonate reservoir consisting of two units AA and AB. These units are thin, highly faulted and irregularly-fractured. The matrix permeability of Ahmadi is very low; it ranges between 0.01 and 10 md. However, the secondary permeability is playing a big part on achieving some remarkable production figures.

The reservoir is believed to have some fractures which have been proven from image logs. These make the simulation of the reservoir quite challenging. This paper describes how fractures were incorporated in the simulation of Ahmadi where three different methodologies have been considered. These are: single porosity with seismic attributes enhancement, dual porosity dual permeability (DPDP) and virtual fracture network modeling.

In the single porosity model, the fracture properties were represented along with the matrix properties in one cell. It was done by considering some seismic attributes such as Anttrack and Anisotropy and then using the Attributes distributions to generate permeability multipliers. For the Dual Porosity Dual Permeability model where the matrix and fracture cells are different, the seismic attributes were used again but to generate a stochastic fracture network. Alternatively, the virtual fracture network model was created by having fractures intersecting each well based on some assumptions related to well spacing, fracture aperture and fracture direction.

The listed methodologies are discussed in details in this paper. It was found that the virtual fracture network approach led to fast and robust history matching results. It was also observed that Anttrack and Anisotropy seismic attributes helped to represent the fault and non-fault related fractures in both single porosity and dual porosity dual permeability models.
Analyzing Pressure Transient and Steady State Drawdown Data From Current Formation Tester Tools in Vertical and Deviated Wells With a Consistent Approach
Authors: Larsen Leif , Allain Olivier
Published: February 2017

A consistent and comprehensive analytical approach to model and analyze drawdown mobility and pressure transient data from formation tester configurations ranging from dual-packer interval tests to single and multiple active circular and oval probes located along or around the wellbore is presented, with transient data from both active and observation probes handled. The approach covers wells with arbitrary deviation in isotropic and anisotropic formations.

The methods are based on solutions of Goode and Thambynayagam (1992) for flow to a point on an otherwise closed wellbore with modifications for anisotropy and well deviation. For oval probes and for elliptical probes obtained following transformation from anisotropic to isotropic systems we use a line-source extension of the solution above. Computations for both point-sources and line-sources use points on the edge of an ellipsoidal "bubble-surface" honoring the probe area, including nonstandard shapes caused by coordinate changes. The approach uses numerical integration to infinite flow time for steady-state data and a similar Laplace-space approach for pressure-transient data.

For multiple active probes and individual observation probes spaced out around the wellbore the angular coordinate must be in multiples of 90 degrees for computational simplicity. For non-vertical wells we only consider probes oriented up/down or on a side relative to full well deviation to horizontal. In addition to ensuring added accuracy, our approach simplifies quality checks of mobility data after analyses – to verify that estimated properties are consistent with observations.
An Integrated Surface, Wellbore, and Reservoir Gas Management Approach for the Mature Mauddud Reservoir in Bahrain Field
Authors: Al-Muftah Ali , Hameed Mohamed , Parakh Sameer , Abdul-Latif Abdulla , Al-Anaisi Isa
Published: February 2017

Bahrain oil field being the first oil discovery in the gulf region in 1932 is now in a mature stage of development. Crestal gas injection in the Mauddud reservoir has continued to be the strongest drive mechanism since 1938. Over the last five years, gas injection and fluid production rates have grown three folds with expanded drilling, workovers, and high volume lift activities however there are significant opportunities to increase oil production and optimize gas injection.

Since 2009, a growing number of wells in Mauddud including newly drilled wells were being shut-in due to high gas to oil ratio (GOR) within the limited surface handling capacity. 30% of active producers accounting for 25% of oil production were shut-in by year 2014. Proper evaluation of this opportunity followed by the field implementation has helped to significantly improve the oil production rate, reserves base, and understanding of the Mauddud reservoir fluid dynamics.

To manage the voidage replacement ratio (VRR) associated with the rapid increase in oil producers, gas injection in the Mauddud reservoir has grown from 180 mmscfd to 500 mmscfd between years 2009-2015. A phased optimization program has been implemented to identify the conformance issues, impact of faults, and for optimization of surveillance systems in order to maximize the oil recovery. The VRR optimization program has also shown opportunities to preserve the source gas from Khuff reservoir which is a valuable resource for the Kingdom of Bahrain’s future.

This paper will describe the integration of gas shut-off workovers, selective gas compression, and VRR optimization as excellent gas management tools for maximizing recovery potential in the Mauddud reservoir.
Study of Proppant Erosion in Multistage Hydraulic Fracturing Using Computational Fluid Dynamics Modeling
Authors: Yuan Peng , Zhang Hao , Huang Xu , Han Jiahang , Zhou Quming , Mezzatesta Alberto , Bao Jie
Published: February 2017

Multistage hydraulic fracturing is widely applied for developing unconventional reservoirs with low permeability. The plug-and-perf method is the most commonly used staging method especially for horizontal wells. Fracturing fluids are usually pumped from the surface to create fractures after perforation clusters are established for each stage; next, proppants are placed into the fractures to keep them open. Field and experimental work have shown that proppant transport in multistage plug-and-perf completions can cause severe erosion on perforations. However, modeling proppant erosion process is still an intricate task that proves to be challenging within the industry due to complexity of the problem. In this work, proppant erosion is investigated by using computational fluid dynamics (CFD) modeling. The effects of sand particle diameter, proppant loading, fracturing fluids viscosity, slurry injection rates, and the pipe angle are analyzed to determine the rate of erosion within the perforations. Several erosion models are used and the simulation results are compared.

The numerical simulation results produced by using the proposed CFD model indicate that proppant can increase the diameter of the perforation. The unevenness of diameter increasing would further compromise the fracturing design because of one cluster accepting more fluid than its counterparts and affecting the distribution of the proppants in the cluster. The flow lines and couplings also show significant wear due to proppant erosion. The simulation results using the Oak erosion model are found to agree with the findings in the inside-casing experimental test.

The results of this study indicate that proppant erosion in multistage hydraulic fracturing can be accurately modelled when proppant properties, fracture geometry, and slurry rheology are all considered in the CFD simulation model. The simulation methodology proposed and discussed in this paper provides a better understanding of fluid and proppant behavior and proves that CFD is an effective tool for reducing the wear of perforations and pipes caused by proppant erosion and hence, optimizing hydraulic fracturing design.
Field Deployment of a Rigless Cable Deployed ESP Using a Vertical Wellhead
Authors: Roth Brian A. , Xiao J. J. , Abdelaziz Mohannad , Mack John , Sarawaq Yahya , Reid Richard , Helvenston Andrew
Published: February 2017

Electric submersible pumps (ESPs) are a widely used artificial lift technology. Conventional ESP systems provide power with a cable banded to the outside of the tubing. These systems have drawbacks in terms of installation speed and efficiency. To overcome these obstacles, a novel cabledeployed (CD) ESP system developed for use in a high hydrogen sulfide (H2S) production environment is a future solution. This paper focuses on the challenges, results, and lessons learned from the first field deployment in the world of a rigless high H2S, CDESP system.

A metal jacketed power cable was a key enabler to the CDESP system. The metal jacketed power cable delivers the best protection for a H2S attack and provides a smooth outside diameter that could be gripped on and sealed. The cable had been tested to withstand H2S levels up to 15% and chloride levels in excess of 150,000 ppm with an expected service life in excess of 10 years.

To overcome well control concerns, a vertical cable hanger spool (VCHS) was developed enabling the ESP cable to be terminated below the master valve. In addition to the surface termination of the cable, the VCHS provided hang off and production flow through capabilities.

The CDESP system, using a specialized inverted ESP, required close integration between several equipment and service providers during the development of equipment and procedures to ensure success in the installation of the system. The system's initial deployment was in a benign onshore well that offered ample workspace for the various service providers to learn the unique aspects of this rigless deployment. Of particular importance, the interface between the service providers at the surface cable termination was critical to the successful installation. For this trial test, the well completion was changed from 4½-in. tubing to 7-in. tubing to accommodate the cabledeployed 562 series ESP.

Lessons learned from this field trial will be incorporated into future trials of the technology. The goal of these future trials will be to deploy the technology in offshore H2S wells where high rig costs can be significantly reduced through the use of lower cost barge coupled with increased speed, efficiency, and ease of CDESP deployment.
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

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

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

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

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

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

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

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

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

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

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

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

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.
Intelligent Completion in Laterals Becomes a Reality
Authors: Bouldin Brett , Turner Robert , Bellaci Isidore , Abu Ahmad Yousif , Dyer Steven , Oliveira Thales , Bin Al-Sheikh Ali
Published: February 2017

For many years, Saudi Aramco and Schlumberger have collaborated to develop a downhole system to merge multilateral technology and intelligent completions to create the world's first "smart laterals." This was the vision of Saudi Aramco's push to drive ever higher recovery factors, an extreme reservoir contact (ERC) approach to reservoir management. These wells can contain upward of 20 km of reservoir contact and require appropriate compartmentalization to ensure uniform heel to toe production throughout the reservoir.

Proactive reservoir control is crucial for the efficient sweep of heterogeneous formations. This paper describes a full-scale multi-lateral, multi-compartment intelligent completion where many new technologies were integrated and demonstrated: Well construction and deployment practices to allow electrical umbilicals to be branched into laterals using inductive couplers.Deployment of revolutionary low power infinite position electrical flow control valves.Validation of a fully integrated production monitoring system providing direct downhole measurements of pressures, temperatures, flow rates, and water cut for each compartment.Integration of the surface acquisition and monitoring system with production SCADA to provide real-time downhole production information and health status.

The ability to finely control downhole flow, measured directly at the reservoir face, has changed the way the industry will approach reservoir management. The sensing system has been validated with continuous compartment Productivity Index (PI), and multirate testing without shutting in the well. The SCADA integration allows a real-time management function where a compartment can be controlled to a target flow rate or draw down directly without resorting to traditional well system models to estimate choke orifice settings.

This paper highlights the development, installation, and validation of this new ERC well system and identifies some of the immediate production impacts emerging from this level of visibility and control at the formation face.
Seismic-Based Detection of Stratigraphic Traps and Carbonate Mounds
Authors: Alsulami Sulaiman , Ameen Mohammed
Published: February 2017

Tectonostratigraphic analysis using 3D seismic interpretation calibrated with borehole data was conducted as part of exploration effort and enabled the prediction of mid-Cretaceous depositional facies and reservoir architecture. The study helped to identify areas with hydrocarbon potential, within the Mauddud Member of the mid-Cretaceous Wasia Formation.

Based on seismic stratigraphy and facies interpretation, in conjunction with structural restoration, stratigraphic architectural patterns were identified as complex carbonate mounds formed in a back-shelf setting. The carbonate mound architecture within the Mauddud Member exhibits high-amplitude discontinuous reflectors, truncation of clinoforms, and stratigraphic-dipping reflection patterns. Several styles of carbonate mounds were identified, including carbonate clinoforms prograding towards the southeast and carbonate build-ups developed as isolated lenses.

Structural restoration is used to verify the syndepositional paleo-highs that are interpreted to be carbonate mounds. The carbonate clinoform dip-magnitudes as observed in borehole images are higher than the regional bedding dip. Clinoform dip-azimuth is similar to the 3D seismic observations.
Application of Dynamic Temperature Modeling for Planning High Temperature Well
Authors: Suryadi Hendrik , Bolchover Paul , Xin Chen , Jun Azrin Soh , Kurnia Agus Ziyad , Whitmore Andrew
Published: February 2017

The ability to drill wells in high temperature formations is limited by the temperature specification of the available drilling tools. Most drilling tools currently have a temperature rating of 150°C, and there is an ongoing effort to develop tools with a higher temperature rating. A parallel effort is to develop the modeling capability to simulate the complex downhole temperature environment, to allow engineer to understand the temperature effect on drilling operation and better manage the temperature-related risks.

Many high temperature wells are planned in an extremely conservative manner. The engineer will rely on the formation temperature measured in offset wells to determine temperature gradient of the planned well. This temperature gradient will be used as a reference for all aspects of the well design, including drilling tools selection, cementing design, etc. In reality, there are many factors which affect the actual downhole temperature experienced by the tools. There is a complex interaction between heating from the formation, drilling fluid circulation, and the mechanical action of drilling tools. There are many forms of energy loss contributing to the downhole temperature, such as mechanical friction, rock cutting, and fluid friction.

A new state-of-the-art dynamic temperature model is developed to simulate downhole conditions in order to precisely predict downhole temperatures. This paper will explain the development of dynamic temperature modeling and how the model being used to plan high temperature well. The paper will also present several case studies where the modeling was used on planning high temperature well and comparison between model results and actual downhole temperature measurements.