bluuebunny/crossref_metadata_2025_split huggingface dataset:
Decoupling of Channeling and Dispersion Effects by Use of Multiwell Tracer Test
Authors: Shen Tong , Moghanloo Rouzbeh Ghanbarnezhad , Tian Wei 
Published: October 2017

SummaryThis paper examines the decoupling of small-scale heterogeneity (dispersion) and permeability variation by use of multiwell tracer-test data. Tracer transport in heterogeneous reservoirs is governed by spreading (because of the spatial variability of permeability) and mixing (caused by dispersion); the combined effects of these two phenomena can be described after very long time periods (rarely met in practice) by the Taylor (1953) theory of asymptotic dispersion.A new formulation is presented to study tracer propagation along streamlines in heterogeneous reservoirs. The streamlines are modeled as analogous reservoir layers with no crossflow. The fraction of layers in which tracer transport occurs faster than the solution of the convection/diffusion equation (CDE) is determined; this fraction represents layers through which channeling may take place: obviously, the larger the fraction, the lower the sweep efficiency. Moreover, a field example is used to demonstrate how to decouple the convoluted effects of the channeling from small-scale heterogeneity.An accurate estimation of “true” dispersion is an essential step in designing a successful enhanced oil recovery (EOR). Furthermore, the sweep efficiency of heterogeneous reservoir can be estimated through interwell-spacing heterogeneity; this improves performance predictions and the economic evaluation of the project.
Gas Lifted Wells Optimization Based on Tubing Head Pressure Fluctuation
Authors: Abbasov Askar , Suleymanov Arif , Abbasov Elkhan , Novruzaliyev Bahram 
Published: October 2017

Abstract
The paper describes how to evaluate the gas lifted well performance with respect to optimum gas lift injection rate based on tubing head pressure fluctuation analysis.
Well and reservoir is a complex system with multiple performance parameters. In industrial practice to acquire some of these parameters surveillance activities are required. Well performance parameters such as rates and pressures are fluctuating with time. These fluctuation characteristics' analysis allows describing certain reservoir and well system parameters and well performance evaluation. The fluctuation is impacted by various factors. For example, fluid flow in porous media characteristics, non-equilibrium fluid inflow behavior, flow composition, flow regime, etc. The particular described method is based on tubing head pressure fluctuation analysis.
Applying various fluctuation analysis methods on the common production properties oscillations allows evaluating actual well performance parameters. The study performed demonstrates the ability to define the optimum regime for the gas lifted wells based on the tubing head pressure or production rate fluctuation analysis without any dedicated surveillance activities. Such an approach was applied in the gas lifted wells production flow rate analysis at various gas lift injection rates - below, above, and at the optimum gas lift rate. The study was applied in Oily Rocks offshore oil field. The obtained results proved the approach being feasible, not requiring dedicated or additional surveillance, and hence, being cost effective.
Low Salinity and Low Hardness Alkali Water as Displacement Agent for Secondary and Tertiary Flooding in Sandstones
Authors: Suleimanov Baghir A. , Latifov Yashar A. , Veliyev Elchin F. , Frampton Harry 
Published: October 2017

Abstract
This paper discusses the low hardness alkali water composition (LHAW) application in a secondary and tertiary EOR operations. It was presented impact of low salinity (LSW) and low hardness alkali water composition on surface tension reduction, contact angle changes, adsorption, emulsion stability and clay swelling. It was observed more stable emulsion (w/o) formation and clay swelling decrease while LHAW deployment. LHAW-2 and LHAW-1 application in secondary treatment mode increased oil recovery (%OOIP) more than 29% and 25% consequently at water-free period in compare to SSW, but finite oil recovery increase was 21% and 15% respectively. Oil recovery increased in tertiary treatment mode was more than 13% and 10% for LHAW-2 and LHAW -1 injections consequently in compare to LSW. It was observed that oil recovery rates for LHAW solutions has not linear relationship as it was for LSW. The observed effect was explained by emulsions generation while water-cut is up to 50%, but while it exceeds 50% the rate stabilizes.
Core Flood Study in Dunga Oil Field, Western Kazakhstan
Authors: Urakov Askar , Runge Trevor , Cumming Daniel , Kundu Dibyatanu 
Published: October 2017

Abstract
As part of Dunga oil field water flooding program, well injectivity impairment analysis through series of core flood laboratory experiments was conducted with the primary objective to ascertain reservoir plugging possibility of the solids/fines contained within injection water that comprises combination of Produced Water (PW) and planned Caspian Sea Water (CSW). The quality of water and its compatibility as re-injection fluid requires investigation to ensure considerations from a reservoir management perspective are built into the facility water handling design criteria.
The scope of this study utilizes industry standard workflows of core flood experiments customized to suit required conditions using real CSW and PW samples. The later stage of the analysis uses various combinations of synthetic brine representing compositions of PW and CSW covering various levels of turbidity. The use of synthetic brine enables varying water filtration standards to be applied/simulated, and to determine the impact of individual elements on formation damage / permeability degradation.
Based on observations, CSW Core flood tests do not exhibit plugging/formation damage effect. This implies that formation fines migration or clay swelling in low saline water environment is not an issue for the Dunga field. Furthermore, the relatively low volume of total suspended solids (TSS) and low fluid pH index explain no detrimental impact of its injection into the tested core plugs.
Variation of total suspended solids content in injection water imparts significant damage to the tested core plugs. PW Core flood with high TSS shows instantaneous severe plugging with drastic permeability degradation. Whereas, PW Core flood with low TSS displays slight (tolerable) level of plugging that could be partially restored by chemical acid treatment. When CSW and PW blend is injected into formation, no fluid compatibility issues were observed. Instead, the plugging potential of the mixed injection water is diluted via increasing CSW content which contains lower TSS volumes.
All key findings related to real water samples have been ratified with synthetic brine experiments that helped identify an impact of individual water property on deliverables. Recommendations for injection water filtration scheme for the Dunga field were delivered as a result of this study which should positively impact the ultimate recoverable volumes of the development.
Implementing Liner Drilling to Achieve Increased Well Construction Robustness
Authors: Grindhaug Gaute , Wenn Torgeir , Eidem Morten , Schwartze Sascha , Regener Thorsten 
Published: October 2017

Abstract
Casing and liner drilling is widely regarded as a method to overcome challenges related to formation instability. Its use and experience is gradually gaining foothold as its benefits and functionality in many cases can be the solution and risk mitigation to overcome some of the Oil & Gas industry's challenges related to drilling wells with narrow drilling margins, depletion and formation instability challenges in traditional well construction.
The technology has now been matured over the last 5+ years and, even though the full potential has yet to be fully explored, several "un-drillable" wells have been made drillable by using its ability to combine the drilling and logging in complex 3D wells while simultaneously securing the wellbore.
The second generation of the technology is currently being field trailed as 7in system, but several different configurations are already available, including a 6 × 8 ¾″ Integrated Underreamer, inner BHA repositioning functionality to remove 6″ rathole for the BHA along with several simple but very robust solutions for liner reaming purposes.
The traditional Steerable Drilling Liner System (SDL) is available for 8 ½ and 12 ¼″ holes sizes, whereas the second generation will initially be available for 8 ½ – 8 ¾″ hole sizes.
This paper will focus on benefits and experiences from using the technology along with an update on the new features that is gradually being made available as part of the second generation SDL technology.
First Intelligent Multilateral TAML5 Wells on Filanovskogo Field
Authors: Golenkin Mikhail Yurievich , Latypov Artur Spartakovich , Shestov Sergei Alexandrovich , Bulygin Igor Alexandrovich , Khakmedov Azat Meredovich 
Published: October 2017

Abstract
First Intelligent multilateral TAML5 wells on Filanovskogo Field is the great example of how new technologies help to optimize CAPEX, and, thanks to higher productivity index, achieve higher production rate. Multilateral well geometry combined with ability to monitor and control each leg separately helps to optimize flow patterns, prolongs well life and contributes to higher cumulative production. The paper focuses on well design, project execution and production results.
In order to achieve results, work was done in several phases: Choose well design which would optimize CAPEX and allow to reach production and recovery targets.Perform two trial jobs on existing mature field to learn technology and prove the concept.Use experience gained on trial jobs to optimize requirements, well design and procedures.Execute the job, control and manage execution to ensure compliance to the plan.Review first production results and estimate benefits obtained from project execution.
This paper describes all the steps focusing mainly on installation procedure, execution and production results review.
As a result of the work done, LUKOIL successfully installed two first intelligent TAML5 completions on Filanovskogo field and achieved ~20%-60% higher production than on nearby single bore wells (up to 38000 bpd). This first wells proven that contemporary intelligent and multilateral completion technologies are mature enough to deliver consistent results. Production results show that actual productivity index matches predicted one. This shows once again that intelligent multilateral well design gives a number of benefits, such as slot preservation, higher productivity indices, faster production buildup and can facilitate reaching higher cumulative production from the field.
The paper describes introduction of complex intelligent multilateral well design on the field. This practical example can be used for future reference by drilling and production focused petroleum industry professionals to better understand benefits and limitations of existing technologies. Actual production result can also be used as a benchmark for field development planning.
Development of Fracture Models for Korolev Field: Characterization to Simulation
Authors: Levchenko Pavel , Iskakov Elrad , Chalak Amanbay , Zhumagulov Kanat , Turmanbekova Aizhan , Galimzhanov Saken 
Published: October 2017

Abstract
Korolev field is a large Devonian-Carboniferous carbonate buildup with a flow system dominated by natural fractures. Currently TCO is looking into potential IOR opportunities at Korolev field, which might help to unlock additional resources beyond the scope of current development plans. Therefore, characterization and modeling of the fracture system is of fundamental importance for a new flow- simulation model to assess and predict IOR performance.
The fracture modeling workflow closely integrates matrix and fracture modeling, which facilitates identification of important parameters for fracture distribution early in the modeling process. Fracture prediction is based on correlations with various geological parameters, such as stratigraphy, depositional facies, mechanical properties and geomorphological features, which provides a soft probability trend for distribution of fracture parameters.
Fracture network characterization based on analysis of well log and core data only is very limited in scale. Pressure Transient Tests (PTT) and Pulse Tests provide important insights into characteristics of fracture network at the larger scale than the conventional wireline data allows. Therefore, it is important to incorporate dynamic dataset as a fracture characterization constraint during modelling of fracture distribution. Most of the wells at Korolev field have good quality pressure buildup and pulse test data. TCO developed a workflow to incorporate dynamic data into the fracture modeling process for the full- field dual porosity, dual permeability (DPDK) model. The first step in the workflow is to calibrate fracture density distribution to match well productivity indices (PI) observed in the field. The next step involves dynamic simulation of pressure buildup tests and their comparison to the actual measured data. The last step is to validate the geologic model with available pulse test data.
Dynamic data integration required multiple iterations and loopbacks to fracture characterization and property distribution. Close collaboration between fracture experts, earth scientists and reservoir engineers along the whole process was essential for successful implementation of dynamic data into fracture characterization and modeling. Calibration with the available dynamic data led to better understanding of spatial distribution of fracture properties and provided important additional constraint for the fracture model construction. Improved fracture model at Korolev is the key factor for more reliable production forecasts and evaluation of future development opportunities.
Outcrop Analogue Study of Deformation Bands and Their Impact on Rock Properties of the Productive Series in South Caspian Basin
Authors: Zeynalov Gasham , Alkhasli Shahriyar , Shahtakhtinskiy Aydin 
Published: October 2017

Abstract
South Caspian basin (Azerbaijan) is the principal place of hydrocarbon accumulation in Productive Series sandstone reservoirs. The basin was complicated by total sub-meridional contraction as a result of north-east compressional deformation which caused generation of deformation bands in various rock types of plunging anticlines with significant influence regarding rock properties. The objective of the study is quantitative estimation of deformation bands impact on rock properties based on field measurements held in Yasamal Valley outcrops in northern-west part of the South Caspian basin and integration of acquired data to analogue steeply dipping reservoir rocks of South Caspian basin.
Geological factors as lithological, structural and petrophysical elements are controlling deterioration or potential enhancement of the rock properties in the South Caspian basin with high concentration of deformation bands. Natural gamma radioactivity, permeability, dips and strikes measurements across wide range of facies were integrated for understanding the impact of these factors. Outcrop plugs with and without deformation bands were tested for Routine and Special Core Analyses, petrographical description, SEM, XRD and CT scan tests to estimate the rock properties at the pore scale.
Field gamma ray measurements analysis reveal that no deformation bands are expected in the rocks with shale volume higher than 32%. Furthermore, probability function of deformation bands occurrence has exponentially declining nature. Higher concentration of deformation bands was observed in the northern part of the Yasamal Valley, where larger volume of iron- bearing calcite-cement precipitation during burial diagenesis has taken place and caused reduction in porosity and permeability. These calcite cements were precipitated in channelized sandstone deposition system and most of them are localized in tabular concretions which generally follow the bedding but, in some cases, terminate within a bed across facies. High amount of calcite cement caused greater impact of deformation bands. The intensity of rock degradation is dictated by mineralogical composition and texture properties. In comparison to the host rock plugs taken from the outcrop, adjacent samples with a single deformation band show 33% and 3% decrease in permeability and porosity, respectively. Dip and dip gradient in sandstone beds do not reveal an obvious impact on deformation bands distribution.
Large volume of calcite cement precipitation was observed in Balakhany reservoirs in north-east limb of the Yasamal Valley which caused greater impact deformation bands and reduction in permeability. Isotopic analysis is recommended to be performed for interpretation of the calcite cement origin and the timing of its precipitation. Impact of deformation bands on permeability can be measured at a plug scale, macro scale estimates would require either whole core flooding or numerical modeling.
Application and Challenges of Coupled Model with Complex Surface Network Connected to Multiple Reservoirs
Authors: Kurimov Dauren , Lim Kok-Thye , Urazmukhambetov Berik , Kairbekov Amirbek , Rojas Danny , Kassenov Baurzhan , Aitkazin Mirkhat , Rey Alvaro 
Published: October 2017

Abstract
Due to its complex nature, long term development scenarios have been modeled using a subsurface reservoir centric model, with representative surface constraints such as well head pressure. Near term operating plans, on the other hand, have been based on a detailed surface network model that included a comprehensive representation of plant, flowlines and operating conditions. Each of these models have been calibrated and their accuracy were verified independently.
We have recently implemented a fully coupled reservoir-surface network model consisting of complex surface network, including three processing plants, and two subsurface reservoir models. The model is run using a controller which manages the surface network model running on a PC and the reservoir model running on a Linux cluster.
The coupling modeling approach in long term forecasting becomes essential when the field deliverability is impacted by the dynamic conditions in the surface facilities. The coupled model provides critical insights when major changes are introduced throughout field life, such as major surface facility expansion, surface network depressurizing, differing regional depletion rate in the reservoirs.
This paper presents the advantages and challenges of applying the coupled model in a complex surface gathering system network being fed by several subsurface reservoirs with different pressures. The model provided insight on the detailed and complex interaction between the subsurface reservoir and the surface network, which cannot be achieved using either standalone model (surface or subsurface). The information enabled us to identify opportunities for debottlenecking and optimizing production through management of back pressure in the system.
Oil-Based Stimulation Fluid as Means of Production Acceleration
Authors: Kubeisinova Assol , Viti Massimo , Pitoni Enzo , Izbassov Arman , Moisseyev Maxim , Yessekenov Nartas , Kalabayev Ruslan , Sultanov Yerzhan 
Published: October 2017

Abstract
Karachaganak is a gas condensate field in western Kazakhstan's pre-Caspian basin. The reservoir is a heterogeneous carbonate rock. Oil-based fluids are not extensively employed in stimulation due to their costs. The paper's objective is to describe the issues the operator faced and that led to the field trial of an oil-based stimulation fluid, fluid selection process and the results of the successful application of this technology as a cost-effective means of improving Karachaganak stimulation operations.
KPO finds horizontal wells completed with multi-stage stimulation sleeves isolated with swell packers installed in 6″ open hole as most suitable and efficient method of construction of oil production wells in the Karachaganak field. However, stimulation of wells such as these creates the potential for injection of large volumes of water into the formation which can result in lengthy well cleanups. To provide a solution to this problem KPO instigated a field trial of an oil-based fluid in stimulation.
Water-based linear gel, used as a displacement fluid, comprises the largest part of pumped water volumes. Therefore, replacing gel with an oil-based system would lead to a drastic reduction in the amount of water injected. In the course of a close collaboration with the Service Company, an oil-based stimulation displacement fluid was selected basing on laboratory testing that considered the effect on both the formation and the surface production facilities. A successful field trial then followed that showed reduced clean-up time (and, consequently, reduced greenhouse gas emissions), potential cost savings, and accelerated production. KPO then continued with the use of the oil-base fluid system, and the results of the trial were replicated. The success of the operations shows there is potential to further optimize the nature of stimulation fluids with the intent to decrease injection volumes. In addition, a market investigation of alternative base fluids is currently in progress with the aim of further reducing cost while still continuing to get the benefits resulting from the use of oil-based stimulation fluids.