bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Thermal Data and Challenges of Heat Flow Variations Evaluation for Basin Petroleum Exploration
Authors: Popov Yury Anatolievich , Popov Evgeny , Miklashevskiy Dmitriy , Korobkov Dmitriy Aleksandrovich 
Published: May 2016

Abstract
The present work summarizes the results of analysis of unique experimental data on vertical heat flow variations in different geological structures obtained from 15 scientific supper-deep and deep boreholes drilled to the depths of 1600–12262 m within Russian and ICDP programs. The new workflow was applied for the heat flow estimation which is based on (1) precise and detailed thermal conductivity measurements on more than 30000 cores with the new emerging technologies, (2) usage of more than 100 equilibrium and non-equilibrium temperature logs, and (3) determination of conductive heat flow component within 20–100 m intervals along every borehole studied.
The data on conductive heat flow variations provides an estimate of vertical variations in the convective heat flow component. The latter reflects the information on variations in reservoir and formation properties and heat- and mass transfer processes in reservoirs and formations.
It was established that a conductive component of the heat flow varies between 70 and 100% for the boreholes studied with essential (up to 100%) increase in heat flow within upper depth intervals of 2–4 km in some cases. Terrestrial heat flow values established from the measurements in deep and super-deep boreholes exceed the previous experimental heat flow estimates by 30…130% depending on a region of drilling. During the previous estimates the heat flow values were obtained from the measurements in shallow boreholes and heat flow was determined from averaging temperature gradient and thermal conductivity along boreholes.
The established heat flow variations play an important role in the improvement of reliability of basin and petroleum system modeling and prediction of temperatures below the borehole depths. The use of calibrated heat flow distributions is shown to increase the confidence of such studies.

Introduction
Experimental data on heat flow density and rock thermal properties (thermal conductivity and volumetric heat capacity) are critically important for basin and petroleum system modeling. The results of the modeling depend essentially on heat flow density values and thermal property values for the sedimentary basin under studying integrated in the model. The rock thermal properties determine formation thermal regime in its natural state as borehole as at thermal methods of EOR.
It is considered normally that satisfactory data on heat flow and thermal properties could be found in publications and it is a usual practice in oil/gas science and industry at basin and petroleum modeling at present.
Influence of Small-Scale Lateral Heterogeneity on Seismic Velocity Analysis and Time-to-Depth Conversion
Authors: Takanashi Mamoru 
Published: May 2016

Abstract
Reservoir depth map is often produced by the time structure map and vertical velocity estimated based on seismic (stacking) velocity analysis. Although seismic velocity is generally the only available velocity information away from well locations, it may not match with the velocity estimated at well locations. VTI (transverse isotropy with vertical symmetry axis) is widely recognized as a typical source of difference between the seismic and vertical velocities and hence the misties in time-to-depth conversion. However, small-scale lateral heterogeneity (LH), often associated with velocity lenses such as channels in the overburden, can cause more significant errors in both time- and depth-domain velocity analyses. I discuss the influence of a thin laterally heterogeneous layer on the normal moveout (NMO) velocity for stratified media using an analytic description. The analytic result shows that distortion of the seiemic velocity is caused primarily by lateral velocity curvature (i.e., by lateral velocity variation with the scale smaller than the maximum offset). The heterogeneity-related distortion increases with the maginitude of velocity contrast and with the target depth. Furthermore, application of the Dix differentiation (used for conversion from NMO velocity to interval velocity) can significantly amplify the lens-induced distortion. The analytic results also indicate that small velocity errors can increase with depth in migration velocity analysis as well. A field example shows that lens-induced 20–30 ms time distortion (pull-up or push-down anomalies) leads to a few hundred m/s errors in the seismic velocity, which are close to the results estimated by the analytic method. The presented analytic approach should help quick evaluation of the seismic velocity analysis and prevent from significant errors in reservoir depth estimation.
Efficient Reservoir Modeling-Statistical Approach for Evaluation and Development of Future Waterdrive Undersaturated Oil Reservoir Performance
Authors: Al-Mudhafer Wathiq Jassim Mohammed , Al-Khazraji Ahmed Jaber 
Published: May 2016

Abstract
For achieving optimal reservoir management, an insight view towards good understanding of the reservoir behavior should be attained. Then, an efficient design of integrated reservoir modeling is a crucial requirement for planning of an optimal future development especially in mature oil fields. The field under study is South Rumaila oil field/ main pay. It is a mature oil field located in South of Iraq with around 59 years of production history. It has 40 producing wells and 20 injection wells located only at the east flank to maintain the reservoir pressure since there is an infinite acting edge water aquifer and its strength from the west flank is much effective more than the east flank. A reservoir simulation study has been done to determine the optimal future reservoir performance in regards to the effectiveness of water injection to improve oil recovery.
In this paper, multiplicity scenarios have been done to investigate the efficiency of water injection and consider the streamline-based simulation results for optimal water injectors optimization. This study has considered the cumulative oil production (NP) and net present value (NPV) as an objective functions to find out the optimal decision. In order to find the accurate attainment, the first future prediction scenario has been performed without water injection by running the black-oil reservoir model for future period production of 12 years. Then, full factorial design (FFD) considering water injection rates and number of water injectors as factors has been adopted. Twenty-five experiments have been carried out for the two factors with five levels. The full factorial design (FFD) results showed that the oil recovery is getting higher at the lowest levels of water injection rate and number of injectors; however, the injection rate has the highest effect. The optimal scenario has shown higher cumulative oil production when activate nine wells with 4000 STB/DAY. Never the less, the FFD has shown that the number of activated injectors has the highest influence when the NPV is the objective function and NPV has the highest value at the lowest water injectors. Consequently, the optimal scenario is either considering one injector with 2000 STB/DAY injection rate or to continue with base case of non-injection as there is very small difference in NPV. This optimal injector has connections with 15 producers and should support the reservoir pressure. The validity of the two linear models has been done by t-test, p-value, and F-Statistics & Analysis of Variance (ANOVA).

Introduction
An efficient design of integrated reservoir studies through economic analysis and statistical modeling is a unique way for optimal planning of future reservoir performance prediction. Improve and predict the future reservoir performance requires investigate the optimal ways to improve the oil production for long time. One of the considerable schemes is the water injection.
Rock Physics Modelling in Oil and Gas Field Development, A Methodology for Reservoir Characterisation below Shallow Gas
Authors: M Yusoff Yusma Bazleigh , Radzi Nor Afiqah , Khalil Ashraf , Amdan Amri , Hong Chong Weng , Zeb Jahan , Ting Jimmy 
Published: May 2016

Abstract
A large number of oil and gas fields in the Peninsular Malaysia basin are screened (masked) by shallow gas, resulting in wipe out zones of the underlying seismic amplitudes as well as push down and time delay (sag) of the structural closure of economical oil or gas fields. Such effects lead to significant uncertainties in resolving and mapping of the objective reservoir units below the shallow gas.
On these premises, 3D 4C Ocean Bottom Cable (OBC) seismic survey has been acquired and processed in one of the gas and oil fields in the Malay basin with the objective of resolving the multi-layered reservoir intervals through mode converted shear component data.
This paper will discuss the rock physics and properties model that has been developed as part of a 3D 4C PP-PS Joint Seismic Inversion project with the primary objective of delineating and characterizing the various reservoir intervals and depositional environments of the oil and gas accumulation, a first in Petronas Carigali experience in reservoir characterization. This paper focuses on synthesizing missing logs, log conditioning, seismic petrophysical evaluation, rock physics modeling, invasion correction and fluid substitution to the fullwaveform (P- and S-wave) and density logs to make ready for seismic inversion.
A total of 10 wells with 8 measured P- and S-wave logs are available for this study. The overall qualities of well logs were adequate for the purpose of this inversion project. These data have been used in the generation of rock physics models. The methodology applied was to construct a rock physics model that is consistent with the petrophysical analysis and the elastic properties as given by the conditioned well log data. The model was then applied everywhere to generate synthetic elastic logs and full offset synthetic seismograms that were then compared and matched to the recorded data respectively.

Introduction
Well log data are used to understand the relationship between the reservoir properties and subsurface seismic data. Since well log data provide constraints and calibration in the inversion workflow, their quality directly impact the confidence and the accuracy of the inversion results for quantitative interpretation and follow-on reservoir modeling. Well log quality and consistency are subjected to various factors like variation in tool measurements, borehole rugosity, borehole fluids, elapse time between drilling and logging, invasion of borehole fluids into the formations, alteration of the formation properties due to the presence of the borehole and/or borehole fluids, casing points, and missing data. Therefore, the primary goal in processing well log data is to minimize measurement related errors, generate and fill in the missing data, and to obtain consistent and accurate logs between all the wells.
Uncertainty Analysis Turns Failed Infill Well into an Economic Success
Authors: Ontowiryo M Bambang , Kurniawan Akbar , Sardinda Lalang Jati , Suderajat Suderajat , Priyantoro Jati , Prakoso Ambaria , Sadat Anwar 
Published: May 2016

Abstract
The M oil field is located offshore within the Malacca Strait PSC, Indonesia. Reservoirs are sandstones in the Lower Sihapas (LS) Formation. They have strong water drive, are under-saturated, low viscosity/high API oil, low GOR and high dip angle.
Oil production started in 1986. Current oil rates are 0.6 Mbopd from ten wells with commingled completions. The current recovery factor is over 50%.
Major challenges to further develop this field are high water cuts, and old surface facilities.
In December 2010, the M-10 well was drilled as an attic well. Unfortunately, the oil rate was far below than forecasted, as the six target sands were 42–53 ft deep to prognosis, and oil has already been swept to the offset wells. Only the A sand, and an untargeted Upper Sihapas Formation sand contained clear indications of oil. However, reservoir deliverability from the sands was low due to depleted reservoir pressure and low permeability.
In 2012, reservoir modeling using a geostatistical approach created 21 realizations to cover uncertainty in facies distribution, porosity, permeability and oil-water contact. We adopted three models to represent the P10, P50 and P90 cases. The three models are history-matched based on analysis of probability of OOIP distribution. These models and C//O log as additional data consistently indicated that the B and E sands in M-10 should have good amount of remaining oil, despite the negative indications from gas shows and logs. Nodal analysis showed no cross flow would occur if we commingled these sands with the existing perforation.
Based on these studies, we performed a simple workover operation.
After perforation, the oil rate increased to 280 BOPD and settled down to 200 BOPD. A combination of reservoir simulation, uncertainty analysis, C/O log and nodal analysis turned the M-10 well from zero to hero.

Introduction
The M field was discovered in 1981 and first oil flowed in 1986 from the Sihapas Formation. The reservoirs produce 42° API oil with low GOR. All wells produce commingled from multiple sands with Electric Submersible Pumps (ESP). The reservoir has strong water drive mechanism combined with gravity drainage that make reservoir have high recovery. Currently, over 50% of oil in place has been produced.
Innovative Integrated Approach for Real-Time Liquid Rate Estimation for ESP Wells Production Optimization and Field Production Reconciliation in the Sabriyah Digital Oil Field
Authors: Al-Ali Abeer Khalid , Al-Hamer Mohammad , Hasan Bashar A. , Singh Siddharth , Moricca Giuseppe 
Published: May 2016

Abstract
A reliable liquid rate estimation is critical for evaluation of well and pump performance in wells lifted using electric submersible pumps (ESPs). The estimation of reliable liquid rates is a challenging and complex task even in digital oilfields (DOFs), such as the integrated Kuwait Integrated Digital Field (KwIDF) project in the Sabriyah (SA) field in North Kuwait. The correct liquid rate estimation is necessary to identify the ESP operating point to extend the ESP run life, improve field uptime, and identify production optimization opportunities.
Different methodologies have been adopted to provide the most reliable virtual liquid rate estimation:Real-time rate measurement.Virtual rate estimation based on well modeling using iterations of wellhead pressure (WHP) and pressure drop across the pump.Virtual rate estimation based on a well gradient plot using iterations of WHP, water cut (WC), and gas/oil ratio (GOR).Empirical correlation (tubing head pressure [THP] vs. liquid rate) based on measured data during surface multirate production testing.
This paper describes the approach adopted in the KwIDF SA for the best estimation of the real-time liquid rate in each well. The daily production rate reconciliation approach used in the KwIDF SA field will be discussed as well.
Using this approach, better well surveillance was made possible and an 18% increase in field uptime (equivalent to a 4% increase in production recovery) was achieved. In addition, more effective proactive analysisand a more stringent decision-making process were implemented.
In conclusion, this innovative approach provided more value in terms of asset surveillance compared to that conventionally adopted within the industry.

Introduction
Oil companies sometimes struggle to obtain a produced liquid and oil volume measurement, which is a very important piece of information for reservoir and day-to-day well surveillance and optimization.
In many cases, reservoir and well surveillance relies on monthly back allocation. This type of process creates a time gap between the event and problem identification. In some cases, problems are not identified for months.
Currently, many systems are available that can provide both direct and indirect fluid rate measurements for produced liquid and oil rate evaluation, e.g., a multiphase flow meter [MPFM] combined with a WC meter. This paper describes the use of a combination of different solutions for accurate measurement of liquid and oil rate in real-time. It includes a MPFM, WC meter, and virtual measurement using well models in real time matched with the latest well surface production test available.
The KwIDF SA project has developed a robust approach for estimating the real-time liquid rate and has implemented the use of a WC meter for real-time WC evaluation.
A Decade of Experience with Multiphase Flow Meters
Authors: Al-Kadem Mohammad S. , Al Khelaiwi Faisal T. , Al Mashhad Ali S. , Al Dabbous Mohammad S. , Al Amri Meshal A. 
Published: May 2016

Multiphase flow metering is considered one of the most essential technologies in well testing. Since the mid 1990's, Multiphase Flow Meters (MPFM) have evolved from a revolutionary new technology into a consolidated solution widely adopted by the major operators worldwide. This evolution has taken place thanks to the high quality of measurements, low operational cost and the capability of enabling remote monitoring of wells' performance with ease. The meters have proven to be durable for testing oil wells of Saudi Aramco's (SA) fields.
The installed MPFMs in Northern fields of Saudi Aramco have contributed effectively to enhancing the semi-real time measurements' quality as well as improving reservoir characterization. However, MPFMs are prone to mechanical and firmware failures. To keep the general health of the installed systems, various preventive and ad-hoc services are needed. The MPFM technology largely seems to be performing as expected and delivering high quality data. So far, 58% of the systems have been in service for more than 8 years and continuing to operate efficiently.
Thorough analysis of the routine maintenance and checkups conducted during the past 10 years revealed the following: The MPFMs Mean Time between Failure (MTBF) and Mean Time to Repair (MTTR) indicated that the MPFMs have been available 97% of the time.The use of a probabilistic approach (Monte-Carlo™ Simulation) to study the P10, P50 and P90 values of the maintained MPFMs indicated that the variance between these values is small, demonstrating the reliability of these equipment.The classification of the diverse types of problems faced while operating the MPFMs highlighted the dominant cause of failures and enabled the initiation of a surveillance and subsequent failure mitigation program. The latter program resulted in fewer failures and higher equipment efficiency.
This paper discusses the lessons learnt and experience gained from operating 168 MPFMs provided by different vendors in different environments during a 10-year period, along with the appropriate solutions that were implemented to mitigate the challenges faced and subsequently improve the efficiency and data quality of the MPFM.
Surfactant-Polumer Flooding in Hard Brines and High Temperature Reservoirs
Authors: Delbos Aline , Tabary Rene , Chevallier Eloise , Moreau Patrick 
Published: May 2016

Abstract
Chemical EOR is a common process to increase recovery in oil reservoirs but these techniques are limited today in the case of high temperature and hard brines, mainly due to high adsorption issues and thermal stability of the chemicals. Specific formulations of surfactant and/or surfactant-polymer have to be designed and injection strategy has to be adapted for these challenging cases.
In this paper we first investigate the evolution of surfactant phase behavior in high temperatures and high hardness conditions and the way surfactant formulations can be adapted to these conditions. Specific chemicals are required to withstand challenging environment, specifically high temperatures. Adapted lab protocols are also required including essentially anaerobic conditions. We demonstrate how properly selected chemicals can be successfully blended and adapted injection strategies designed in these conditions.
We then present at the lab scale the effect of temperature and brine composition on surfactant adsorption through oil recovery coreflood experiments. In addition, we show the way adsorption is reduced in the case of hard brines, by the use of a salinity gradient. In these cases, the optimization of the injection strategy can help reduce the surfactant loss. High oil recoveries together with moderate surfactant adsorption can then be achieved opening new opportunities for development of chemical EOR.

1. Background information
Surfactant-Polymer (SP) and Alkaline-Surfactant-Polymer (ASP) have been acknowledged for decades to be among the most promising techniques to enhance oil production and reserves in mature oil fields. These processes consist in the injection into a formation of chemical slugs composed of surfactants, polymer and in some cases alkali [1; 2].
Surfactants are used to decrease interfacial tension (IFT) leading to an additional mobilization of oil initially trapped by capillary forces in the rock matrix [1]. Polymers are used in order to improve mobility control and sweeping efficiency [1; 2]. The addition of alkali leads to a decrease of surfactant adsorption onto reservoir rock, specifically in presence of clays. Additionally, for reactive oils, alkali leads to the in-situ generation of soaps induced by the saponification of acidic crude oil components [3] improving overall process performances.
Most published successful studies so far focus on relatively favourable reservoir conditions. Under more challenging conditions, performance of ASP/SP flooding can drastically decrease [4]. Among specific hurdles, high salinity/hardness and/or high temperature make ASP/SP processes challenging, both at laboratory and field scale.
Integrating High-Resolution Multiwell Image Logs to Improve Geological Reservoir Characterization and Sequence Stratigraphy
Authors: Bahadidah Taleb Ahmed , Dashti Rouhollah , Ismail Mohammed Fauzi , Nair Nisha , Marca Sandra , Abd Malek Alya , M. Yunan M. Izzat Fauzi , Johansson Melissa 
Published: May 2016

Abstract
A high-resolution multiwell geological reservoir characterization and integration study was conducted using subsurface data, including high-resolution images from an oil-base microimager, conventional openhole logs (including gamma ray, neutron, density, and resistivity), cores, mud logs, and 3D seismic data from eight wells. The study was performed on a shallow-water clastic reservoir to analyze the structural dip, reservoir facies, paleocurrent, and overall depositional settings. Ultimately, a sequence stratigraphy procedure was implemented to divide the entire studied interval into a certain number of genetically related stratigraphic packages, which were subsequently correlated with the regional stratigraphic markers in that basin.

Scope and Objectives
The studied field is one anticline structure separated by major bounding faults. This field is located offshore and is a major gas producer. The main producing targets are early to middle Miocene sands. The wells in this study are placed along the fold axis of the field from southwest to northeast, providing a good coverage of the entire area. Therefore, the wells in this study, named A through H for confidentiality reasons, are arranged in cross section from southwest to northeast in the following order: well H, well G, well F, well E, well D, well B, and well A (Figure 1).
The main objectives of this analysis are1.Developing an integrated study to evaluate and extract structural, paleocurrent and depositional characteristics of the main reservoirs in the field.2.Updating the existing well tops, which were provided by the operator, using the newly generated true stratigraphic thickness (TST) index.3.Validating and fine-tuning the existing model using smaller-scale data -images logs- with higher resolution than seismic.4.Resolving some field ambiguities such as pressure discontinuity and formulating solid guidelines for future field development plans