bluuebunny/crossref_metadata_2025_split huggingface dataset:
The First Implementation of Hydraulic Fracturing With Microseismic Fracture Propagation Monitoring in Northeast Thailand
Authors: Wattanasuwankorn Reawat , Kritsanamontri Panyawadee , Limniyakul Vorasak , Sompopsart Suwin , Toempromraj Wararit , Kaenmee Kwanjai , Sa-nguanphon Saksit , Prasittisarn Puchong IntasaloYotsak , Sirisawadwattana Jutaratt , Vattanapornpirom Kanda , Boonyasaknanon Phathompat , Kongdachudomkul Chatchai 
Published: February 2017

Abstract
Low-permeability sandstone formations in deviated exploration wells were drilled and completed in 2013 in northeast Thailand. Reservoir simulation modeling indicated that a well would not produce as a result of the tight formation. Hydraulic fracturing was then considered, and a plan was adopted to use this method to improve the well's production using reservoir simulations. Microseismic fracture monitoring was implemented to correlate data with actual fracture propagation to understand the formation's geomechanics.
The fracture design methods were combined with completion and cleanout strategies to help improve well performance. The fracturing design was incorporated into a complete operational procedure, along with contingency plans, a decision tree, and an integrated communication plan, to allow for possible contingencies. Careful planning, fluid testing, and a fit-for-purpose completion design resulted in a successful hydraulic fracturing operation. The microseismic equipment was installed and monitored during the fracturing operation to provide actual fracturing propagation noise signals.
This paper presents the well fracturing technology, operational procedures, and microseismic technology used to better understand reservoir behavior and geomechanics characteristics. The geophone installation and surrounding control on location provided minimum noise interference for more accurate actual fracture propagation data. The computer program then forecasted fracture propagation. Comparisons between actual fracture propagation and the simulated fracture design allowed the operator to better understand subsurface parameters and characteristics for building the reservoir database. The operator was also able to forecast fracturing dimensions to help prevent water production zones. This significant reservoir information can be used for field development to maximize hydrocarbon production.
Fracturing technology and seismic technology were combined to improve the probability of successful hydrocarbon production. Microseismic results demonstrated the actual fracturing plane dimensions and dynamic fracture propagation, and the fracturing computer program provided fracture simulation dimensions and direction. Combining these technologies allowed the operator to obtain more reservoir data for future field development.
Precise Wet Gas Measurement Using Venturi Meters
Authors: Arsalan Muhammad , Al-Shammari Ahmad T. , Al-Kuait Abdulmohsen S. , Noui-Mehidi Mohamed Nabil 
Published: February 2017

Abstract
This paper presents the methodology of correcting the erroneous reading of the venturi meters for measuring the gas rate when high amounts of liquids, including condensate and water, are being produced from the gas wells. The proposed system takes advantage of existing infrastructure in proximity of the venturi meters and is designed to be retrofitted to the existing meters to knock out the liquid before the meter and recombines it after. This method eliminates the need for an additional flow line to carry out the liquid or a compressor to reinject the separated liquid back into the pressurized gas line.
Close Monitoring of Gel Based Conformance Control by NMR Techniques
Authors: Kwak Hyung Tae , Wang Jinxun , AlSofi Abdulkarim M. 
Published: February 2017

Abstract
Carbonate's extreme heterogeneity in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. However, in-depth conformance control in high temperature reservoirs is still a challenge, due to severe gel syneresis (expulsion of a liquid from a gel) and the associated significant reduction in gelation time.
Recently, we have demonstrated the potential of a selected gel formulation and its favorable impact on sweep efficiency for both water and chemical flooding applications in high temperature and high salinity carbonates (Wang, 2016). In the current work, the performance of polyacrylamide/chromium gel injection followed by water flooding for Arab-D carbonate reservoir rock was closely monitored by 1D T2, spatial NMR T2 mapping and 2D NMR techniques. The NMR measurements before and after waterflooding with and without pre-injection of gel provided the detailed description of spatial oil recovery along the rock core sample under reservoir condition. By comparing the spatial T2 distributions from the experiment with waterflooding and gel injection followed by waterflooding for the core sample with artificial wormhole drilled in the center, which mimics the fluid thief zone, the efficiency of the conformance control by gel was measured. The incremental oil recovery factor of ~14% OOIC after gel injection followed by waterflooding was observed throughout the whole sample with highest recovery in the vicinity of where the wormhole begins near fluid injection inlet. In addition, by analyzing the alteration of spatial NMR T2 and T2-D distribution, the accurate flow paths of the injected water and gel were derived from NMR data.
The results of the current study increase the understanding of how gel could helps to increase sweep efficiency of waterflooding and other IOR/EOR applications in the presence of unwanted highly permeable channels in the reservoir rocks.
Positive Influence of Project Risk Management on Project's Schedule, Quality, and Cost Target
Authors: Bopalia Vinod 
Published: February 2017

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.