bluuebunny/crossref_metadata_2025 huggingface dataset:
Study on Physical Simulation Experimental Technology of Ultra-low Permeability Large-scale Outcrop Model
Authors: Zhengming Yang , Xuewei Liu , Xuan Xu , Yapu Zhang , Xuewu Wang
Published: May 2016

Ultra-low permeability reserves have accounted for a very large proportion of China's proven reserves and undeveloped reserves at present, so it is very urgent to deeply study the seepage flow law of ultra-low permeability reservoirs. This paper proposed a rock screening criterion for large outcrop models. Meanwhile, encapsulation and saturation methods, pressure and flow field test methods for large outcrop models were developed according to the reservoir characteristics and fluid seepage flow characteristics of ultra-low permeability oilfields in each oil region. Based on those new experimental technologies, the 2D nonlinear seepage flow law of ultra-low permeability reservoirs has been studied with the large outcrop models. Experimental results indicate during the fluid seepage flow in a large outcrop model, there is a non-flow area, a nonlinear seepage flow area, and a quasi-linear seepage flow area on plane; in addition, the variation law of pressure gradient field and flow with different displacing pore volumes has been analyzed, thereby laying a substantial foundation for establishing the evaluation methodology for the effective driving pressure system of ultra-low permeability reservoirs.

Introduction

Ultra-low permeability reserves have accounted for a very large proportion of China's proven reserves and undeveloped reserves and developed ultra-low permeability oilfields have become more and more in recent decades[1]. Therefore, it is very urgent to deeply study the seepage flow law of fluids in ultra-low permeability porous media for providing guidance to reasonable development of ultra-low permeability oilfields. At present, all analyses and theoretical studies of the seepage flow law of ultra-low permeability reservoirs are based on one-dimensional physical simulation experiments and microtubule flow experiments[2,3,4] instead of fluid seepage flow experiments on ultra-low permeability plate models, so the corresponding research findings can neither be applied in real ultra-low permeability reservoirs to a relatively large extent nor indicate the nonlinear plane seepage flow law of ultra-low permeability reservoirs.

Experimental studies of domestic and foreign large plate models[5,6,7] focus on EOR, the models are basically sand-packed models, and there are rare large outcrop models used to study the seepage flow law of ultra-low permeability reservoirs. Therefore, this paper has analyzed and studied large outcrop models in terms of rock screening, model making, physical simulation experiment unit, pressure and flow field test methods, fluid seepage flow law in large outcrop models, etc. so as to form a physical simulation experiment technology of ultra-low permeability large outcrop models and lay a substantial foundation for establishing the evaluation methodology for the effective driving pressure system of ultra-low permeability reservoirs.
Performances of 3D Frequency-Domain Full-Waveform Inversion Based on Frequency-Domain Direct-Solver and Time-Domain Modeling: Application to 3D OBC Data from the Valhall Field
Authors: Brossier Romain , Etienne Vincent , Hu Guanghui , Operto Stephane , Virieux Jean
Published: May 2016

This study addresses the performances of different approaches to tackle 3D frequency-domain Full Waveform Inversion (FWI). FWI is becoming an appealing method to build high resolution velocity models from wide-azimuth seismic data. Three-dimensional frequency-domain solutions of the wave-equation for frequency-domain FWI can be computed with several methods. In the frequency domain, direct or iterative solvers can be used to solve the linear system resulting from the discretization of the wave equation. Alternatively, frequency responses can be computed by time-domain modeling coupled with discrete Fourier transform or phase-sensitive detection method. For a large number of seismic sources, the computational time of all of the methods scale along similar lines to the size of the problem, although the performances of the direct-solver approach is hampered by the limited scalability and the memory demand of the lower-upper decomposition of the forward-problem operator.

We implement the direct-solver and the time-domain modeling approaches in 3D acoustic frequency-domain FWI, which is applied to real 3D wide-azimuth OBC data from the Valhall field, North Sea, at low frequencies (< 5 Hz). We show, for this case study, that even if less flexible for high-performance computing, the direct-solver approach is one order of magnitude more efficient in computing time/resources that the time-domain approach, if the signal-to-noise ratio in the data is sufficiently-high to limit the inversion to few frequencies. We finally discuss the performances, pros and cons of both methods, which depend on the wave physics (acoustic versus visco-acoustic, anisotropy, extension toward elastic or visco-elastic), the acquisition geometry (streamer-like versus fixed-spread acquisitions) and the computing architectures (small versus large amount of memory per computing node).
Estimating Saturation Changes from 4D Seismic: A Case Study from Malay Basin
Authors: Pathak Ravi Kant , Bakar Rizal
Published: May 2016

4D seismic is increasingly being used for quantitative estimation of pressure and saturation changes related with production and injection operations (Landro, M., 2001, Christophe Ribeiro et al 2004, MacBeth C. et al, 2004, Cole S. et al 2002, etc). Variations in reservoir properties due to production and injection program induce changes in elastic reservoir properties which are manifested through 4D time shift and attribute anomaly.

In this paper, the workflow implemented for estimation of saturation changes from integrated analysis of well and 4D seismic dataset pertaining to the one field in the Malay basin is presented. The reservoir sands under study are deposited during Miocene age and are comprises of intertidal shales, siltstones, fluvio-tidal channel sandstones & minor coals.

Base 3D seismic data over the field was acquired in 1996 while Monitor 3D was acquired during 2006. Both dataset were processed implementing PSTM processing workflow using similar parameters. The NRMS value of Base and Monitor dataset was found to be 24 which is quite acceptable for quantitative analysis. Even though utmost care was taken during the processing to maintain the repeatability, there are still minor acquisition footprints observed in the Monitor & Base difference volume.

Correlation of Monitor & Base amplitude difference with Pressure Perturbation modeling (MacBeth 2003) suggests that the dominant 4D effect in the area of study is related with the saturation changes due to water injection and production. The 4D analysis workflow implemented for estimating Monitor saturation used Base reservoir model (saturation and porosity), Base & Monitor inversion volumes and ?Sw measured at wells. The workflow used the neural network inferences to predict Monitor Sw.

The Monitor saturation model obtained from the proposed workflow is seismically constrained in the inter-well & beyond the well regions. It supplements/supports existing dynamic model in identifying un- swept oil compartment and effective reservoir management.

Introduction

4D or Time Lapse seismic has established itself as a mature technology to support field development and reservoir management decisions. In Brown fields, 4D seismic is helping to locate bypassed oil, identify un-drained compartment, and optimize the infill drilling program leading to incremental recovery. As a reservoir surveillance tool, 4D provides information support in planning and implementing IOR/EOR operations. It provides information on fluid front position to support in optimizing the injector's locations.
Extending Gas Lift Systems Deeper into the Wellbore Using Capillary Through Tubing Services
Authors: Pate Brad , Stanley Rick , Nghi Nguyen Chinh
Published: May 2016

Introduction:

As wells with existing gas lift (GL) installations mature and reservoir pressures decline conventional GL systems often become less efficient. The lack of reservoir pressure makes it difficult to maintain a fluid level at a depth that allows the existing GL system to be effective. The cost of a work over remediation program to redesign and rerun the existing GL system can at times be considered uneconomical.

Application:

This innovative "Capillary Conveyed" through tubing system can be applied to most wellbores regardless of tubing size or depth.

Results, Observations, and Conclusions:

The first "Capillary Conveyed GL extension system installation was carried out for a major operator offshore Vietnam in January 2012. The existing GL system was no longer effective. The well was unable to flow and was shut in. After the installation the well took several days to unload and stabilize but then flowed continuously for 60 days at rates that exceeded the operator's expectations. After the initial 60 days production the well started to fluctuate and has since been put on a cyclical production regime. Cumulative production from the well from the date of the GL Extension System installation until May 2012 was 43,000 bbls oil. Project payout was estimated to be 4 days.

Significance of Subject Matter:

Wells that were once considered uneconomic due to cost, technical challenges and/or accessibility may now be re-evaluated as candidates for this new technology. This innovative through tubing solution has the potential to reinstate flow to wells where the existing GL system is no longer effective. Furthermore the system can be adapted to allow a new through tubing GL system to be introduced into a well that was completed without a gas lifting system.

Technical Contributions:

Advanced solutions utilizing "Capillary Technologies" provide cost effective production enhancement and improved reserves recovery while maintaining a relatively small foot print. This paper will review a case history where this "Capillary Conveyed" through tubing solution was successfully installed and reinstated flow in a well that was suffering from an inefficient GL system.

Field Overview:

Block 46/02 (Graphic 1) is located 205km offshore south of Ca Mau, the southernmost land fall of mainland Vietnam, and just north of the joint development area PM-3 CAA. The producing Kekwa oil and gas field in PM-3 CAA is located 15km to the southeast of Song Doc Area (SDA).
The Production Facilities Key Safe Technology of Gas Fields with High H2S/CO2 or High Pressure
Authors: He Jun , Yang Lina , Ba Xili , Wang Chunyan , Wang Qi
Published: May 2016

As the shortage of the energy, more and more gas fields with high H2S/CO2 or high pressure will be developed.

China's high sour gas fields are mainly concentrated in the northeastern Sichuan Basin, Daqing Xushen and Jilin. As the representative of high sour gas field Luojiazhai gas field, the H2S content is 9.5% ~11.5%, CO2 7% ~ 8%. In Changling gas field the CO2 content as high as 27%.

High pressure and high yield gas field are mainly concentrated in the Tarimu Basin Kela 2 gas field as the representative, single well yield is 105~140MMSCFD, wellhead flowing pressure up to 63.1MPa, corrosion is mainly from Cl- and CO2 the content of Cl- in produced water is up to 100667mg/l.

For these gas fields developed still on initial stages in China, there are a series of difficult problems of safe technology for production facilities. Aiming at these problems, the paper introduces CNPC's safe technology by research. The production facilities key safe technology includes process technology, material selection, setup of safety instrument, safety relief, safe distances.
Fracture Modelling Using Seismic Based Fracture Intensity Volume, a Case Study in Middle East
Authors: Hansheng Mu , Chuanxi Liu , Peng Li , Huihua Pang
Published: May 2016

In this paper, a case study in a fractured carbonate reservoir is presented to demonstrate the approach of fracture modeling using fracture intensity volume. Fracture information described from well data and fracture prediction data generated from pre-stack seismic data are both used to establish discrete fracture model.

FMI logs, mud losses, log interpretation results and production data are used to describe fracture characteristics on each well. Fractures are divided into 4 sets based on fracture scales, fracture dip and strike interpreted from FMI log. Fracture density logs for each set is generated separately, and each set of logs is used separately for fracture modeling. Seismic attribute of pre-stack azimuthal anisotropy is generated. This attribute volume is compared with FMI interpreted fracture density along wellbores for over 120 wells. The consistency of seismic attribute with well data is good for 90 per cent of wells. Hence the seismic attribute of pre-stack azimuthal anisotropy is used as fracture intensity volume for fracture prediction.

A DFN model is established for each set of fractures using FMI interpreted fracture density as hard data and the seismic based fracture intensity volume as constraining data. Fracture properties are calculated based on discrete fracture network and calibrated by well test analysis.

Introduction

The characterization of fracture reservoirs is one of the biggest challenges for geoscientists. It is attractive to us not only because of the contribution that fractured reservoirs have made to oil and gas production, but also because of the complexity of fracture system. Many attempts have been made in the past to find ways predicting fractures. Geomechanical researchers try to construct a fracture mechanical model from tectonic history (Mace et al., 2004). Geologists try to characterize fractures from facies type, porosity, and reservoir zonation. Geophyisists try to forecast fracture system by seismic properties, acoustic impedance, and spectral imaging attributes (Creties Jenkins et al., 2009). In this paper, an integrated approach is used for fracture prediction and fracture modelling. Fracture features including fracture inclination, azimuth and density are summerized in each zone from image logs. Some normal seismic attributes such as curvatures, ant-tracking volume, coherence volume, are calculated. What is more, a fracture intensity volume based on pre-stack anisotropy attributes calculated by FRS software is used. By using fracture density logs calculated from image logs, an integrated fracture intensity volume is interpolated with the combined seismic volume as a trend. This fracture intensity volume is used for creating Discrete Fracture Network.
Microfacies Analysis and Reservoir Characterisation of Late Cenomanian to Early Turonian Mishrif Reservoirs, Garraf Field, Iraq.
Authors: Ali F.H.M. , Ali Z. , Embong M.K. , Azmi A.A.
Published: May 2016

Garraf field is situated in southern Iraq, in Thi Qar Governorate. It was discovered in 1984, and proven to have hydrocarbon accumulation in Middle and Lower Mishrif by exploration and appraisals wells in Garraf. It has low relief gentle anticlinal structure aligned in NW-SE direction and has a dimension of 10km in width x 31 km in length. The Mishrif Formation were deposited in Mesopotamian Basin during the late Cenomanian to Early Turonian. Mishrif is a limestones formation with the approximate thickness of 200m.

Mishrif Formation is the major reservoir and contributes almost 70% of the field's total STOIIP. For the field development plan, a 3D subsurface model was developed for resource assessment and production prediction. However, due to limited wells availability in Garraf, the main challenges are modelling the reservoir continuity and heterogeneity throughout the field to ensure the resulted model represent the actual Mishrif Formation. For the last few years the understanding on the reservoirs were solely based on the regional information, however with the recently acquired conventional core from Mishrif formation and the availability of acoustic impedance from 3D seismic data give an opportunity to investigate the reservoirs in more details.

Information on the depositional environment and the facies distribution are very crucial during the facies and petrophysical modeling stages to ensure the resulted 3D model represent the actual subsurface condition. The objectives of this exercise are to integrate all the information and develop the depositional model and characterise the Mishrif reservoirs.

Procedures

All microfacies identified were from the core and thin sections and their reservoir characteristics were predicted based on the observation on the compositional and textural variables. Their specific depositional environment were modeled based on Wilson Microfacies Model (1975) and Standard Facies Belts (1975) with broad shelf. Each microfacies identified were grouped into several hydraulic units (HU) based on their flow zone indicators (FZI). Upon the calibration with the cored intervals, the FZIs were extrapolated to the uncored intervals. The rock typing (RT) were compared with the microfacies to ensure its vertically matched with each microfacies distribution. The hydraulic units were extrapolated to the uncored intervals and wells by using multi liner regression. The resulted RTs from this process were converted into microfacies based on observation from the cored wells, acoustic impedance, and regional settings.
Development of Detection Techniques for Monitoring and Optimising Biocide Dosing in Seawater Flooding Systems
Authors: Al-Moniee M.A. , Al-Abeedi F.N. , Koopal C. , Akmal N. , Sanders P.F. , van Veen S.
Published: May 2016

Anaerobic microorganisms which are frequently associated with corrosion fail Control of bacterial activity are posing major challenge in Saudi Arabia's massive seawater flooding systems. Biocides are used to control bacteria throughout the oil industry. A study to explore the feasibility to develop a detection technique for biocide batch treatments, preferably on-line and in real time, for their potential use in seawater flooding system network is described. Several methods to measure key components of the biocide composition were investigated in the initial stage. Three different techniques were explored during the feasibility phase study to detect and measure concentrations of biocide in seawater. This helped our plans for designing a sensor based on such detection techniques. The techniques explored were to monitor change in temperature, change in pH, and change in chromophore concentration (colorimetric) in the enzymatic reaction.

The investigated methods included the use of acetylcholine esterase, based on the pH change as a result of acetate formation, the production of reaction heat (thermal) or on the colorimetric detection of the chromophore concentration based on the conversion of acetylthiocholine in combination with a chromophore. It was found that the colorimetric system was the most versatile system to perform the measurement to be able to show the feasibility of the method in real sea water samples and to demonstrate the effects of the biocides on the measurement system.

1.0 Introduction

In water flooding systems, deoxygenated and filtered seawater is injected at strategic points along the periphery of the oil reservoir, displacing the oil and "pushing" it toward oil supply wells in the center of the formation. The technique enhances crude oil recovery substantially and allows for greater returns from the field.

The seawater flooding system in Saudi Arabia is the largest of its kind in the world. It is deoxygenated water and treated with various organic biocides mixtures. The short duration, high concentration batch biocide treatment is designed to prevent the growth of bacteria in the system, thereby minimizing biofouling, water quality deterioration and Microbially Influenced Corrosion (MIC).

Since the system's size is massive, it is very challenging to detect the arrival of a biocide slug treatment at the far water injection wells. Furthermore, quantification of biocide residual concentration in 'real time' at remote desert locations is not currently possible. Developing sensor technologies, which will quantify biocide residual concentrations hundreds of kilometers from the biocide injection location without manual sample collection and conventional wet chemistry analysis, is challenging.
Reef and Sand Reservoir Appraisal in Well-Absent Place: A Case Study in a Marine Area
Authors: Fan Chunyan , Song Yan , Jiang Zhenxue , Zhang Yuanyin
Published: May 2016

The inspiring but indeterminate scenery, that the reef extensively developed in our researching area with obvious bright-spot reflection and distinct seismic velocity drop could be filled by favorable gas, and the blurry reflections below the reef may correspond to periods of turbidity sand reservoir, needs to be more precisely and carefully appraised for further exploration with no hesitation. However, AVO inversion can not be efficiently applied in this unexploited place due to wells insufficiency, even though it is recognized as an excellent method for reservoir prediction and famous of its inverted real P-wave result and other abundant elastic attributes. To efficiently appraise the reservoir quality in this area, an advanced well-absent AVO inversion method, which constructs pseudo-wells according to the seismic interval velocity, amplitude and known message, is put forward and successfully applied in this paper. It is the first time to reasonably appraise the reservoir quality in our working area. The new well-absent inversion method could overcome the prediction obstacles in the early phase of exploration, and suitable for offshore exploration.
3D Petroleum System Modeling Study on Pearl River Mouth Basin (South China Sea)
Authors: Vitagliano Eleonora , Galimberti Roberto , Dalla Rosa Matilde , Gilardi Matteo
Published: May 2016

3D Petroleum System Modeling Study has been developed by using the Eni E&P Division internal package (e-simba™) in order to evaluate the petroleum potential of the Pearl River Mouth Basin, in the South China Sea.

Pearl River Mouth Basin is a Mesozoic-Cenozoic passive margin rift basin oriented NE-SW and parallel to the continental shelf. Within the Basin two main source rocks are recognised in the syn-rift succession: the organic levels of the Enping Formation, Oligocene in age and mainly terrestrial, and those of the Wenchang/Enping Formation, Oligocene/Eocene in age and mainly lacustrine.

Based on geochemical analysis of well data, the Enping source rock is modelled by using terrestrial kerogen type, TOC 1%, HI 250 mgHC/gTOC, 100 m of thickness and kinetics from analogue of Mahakam Delta. The Wenchang/Enping source rock is modelled by using lacustrine kerogen type, TOC 4%, HI 600 mgHC/gTOC, 100 m of thickness and kinetics from analogue of Green River.

Thermal data coming from wells and confirmed by literature suggest an average geothermal gradient of 35°C/km. The heat flow values at Present time match with well data. The creation of heat flow map was done by using a geostatistical approach, kriging with external drift method - software ISATIS, and by considering the correlation between the calibrated heat flow value at single well and the geological trend. Over the study area the heat flow trend correlates both with seismic and magnetic basement.

The results of thermal model integrated with geochemical well data (CO2 and gas maturity) show that the heating better correlates with seismic basement and allow to define the positioning of the organic matter level. A terrestrial source rock can be located in the shallower part of the Eocene/Oligocene sequence while a lacustrine one can be localised in the depocentral area at the base of the same sequence.
Broadband Processing of Conventional Marine Streamer Seismic Data
Authors: Zhou Zhengzheng , Xu Bing
Published: May 2016

We have developed WiBand, a de-ghosting and broadband processing method that can be applied to conventional streamer data acquired with single component streamers. We recorded, over one sail line, multi-streamer data with the streamers towed at different depths, obtaining data over multiple subsurface lines (tracks) parallel to one another. We apply WiBand to each track independently to remove the effects of the source and receiver ghosts. We compare the WiBand results from a deep tow track to conventionally processed result from a shallow tow track to validate the phase fidelity of the de-ghosting process. The results lead us to conclude that WiBand correctly removes the ghosts and recovers broadband data from deep tow streamer data.

Introduction

The vast majority of marine seismic data are acquired with conventional towed streamer cables which are equipped only with hydrophones and are all towed essentially at the same constant depth for any single survey. The receiver ghost zeros out the spectral response of the recorded data at notch frequencies equal to any integer divided by the ghost delay time, limiting both the top end of the usable spectrum as well as attenuating the low frequency response. The source ghost has a similar effect. The combined effect of the ghosts results in greatly reduced resolution in the subsurface image. A conventional "solution" for this problem is to tow the sources and streamers shallow (at less than 7m of depth below the surface) to obtain higher frequencies, at the expense of attenuating low frequencies and exposing the sensors to a noisier environment near the sea surface.

There are currently several acquisition methods that can mitigate or remove the effects of the ghosts and obtain broadband seismic images (Carlson, 2007, Posthumus, 1993, Soubaras, 2010). These methods require nonconventional data acquisition, either with streamers equipped with multi-component sensors, or with streamers configured in unconventional geometries such as over-and-under or slanted configurations. Such methods are not applicable to conventional streamer data.

We have developed an effective broadband processing method based on a new de-ghosting technique. It can remove most of the ghost effects from conventional streamer data. In this paper we will refer to this method as WiBand. This method is designed to address both the amplitude attenuation and the phase distortion introduced by the ghosts to obtain nearly flat spectral response in the typical range of 4Hz to 150Hz, as well as a compact, well focused seismic wavelet. In order to validate our method, we carried out an experiment where multiple streamers were towed at different depths, and evaluated the phase reconstruction fidelity of the algorithm by comparing the WiBand result from the deep tow data with the standard processing result from the shallow tow data.
Remote Real-Time Analysis - A Game Changer for Remote Operation Centers
Authors: Saeverhagen Erland , Thorsen Arve , Dagestad Jan Ove , Spanovic Nic , Cannon Katherine
Published: May 2016

Drilling, completion, production and general surveillance are all areas that benefit greatly from remote real-time analysis, providing significant value to operators through proactive, rather than reactive, responses to challenges during day-to-day operation. Several different disciplines that previously operated separately are today integrated in their work; both in the field and remotely, continual monitoring and remote data analysis includes and integrates areas such as drilling optimization, pressure management, pore-pressure predictions, and wellbore stability. Software models that utilize case-based reasoning and physics, together with real-time drilling and well data, enable immediate situational analysis and trend monitoring. Advice today is provided remotely, requiring fewer personnel at a rig site. However, there are several challenges to remote services with many of these elated to communications issues, a fear of job loss and working outside a comfort zone. What is considered an important development goal for a business might be regarded as a threat for an individual, leading to reduced development within remote services. This paper presents the consequences of an ever-more automated oil field - benefits, challenges and a future outlook.
Two Years Down the Road in Production with Downhole Flow Control Solution in SS Field, Offshore East Malaysia - Success Case Studies, Lesson-Learnt and Way Forwards
Authors: Noridah N. , Saiful M.M. , Anuar M.Y. Saiful , Nur Hazrina K.Z. , Hayat N. Zadil , Gordon Goh K.F.
Published: May 2016

Developed amidst some of the most challenging offset brown fields in the S clusters offshore East Malaysia, SS field has undergone a rigorous drilling and completions campaign extending from Q4-2009 to Q1-2011(i.e. 15 months). 14 wells with downhole flow control solution plus 3 water injectors for long-term pressure maintenance were planned. A campaign of 12 'passive' Inflow Control Devices, ICD's wells and 2 'active' cost-effective surface-controllable intelligent wells was executed with success.

All wells are horizontal to optimize well counts in penetrating more layers and drainage across entire reservoir of approximate 40m thick oil column. However as predicted in the dynamic reservoir modeling, under the huge threat of a large and expanding gas cap (i.e. m size of 2) coupled with the underlying moderate aquifer strength of imposing water encroachment; all the wells, if completed without downhole flow control, will get early gas and/or water breakthrough in a matters of days/months with huge oil bypassed. Hence, the notions of smart and/or advance completions for downhole inflow control solution are to promote this field development into solving the predicted sub-optimal production in order to achieve the target recovery factor of at least 30% in this challenging multi-stalked, very heterogeneous and highly-dipping reservoir.

In this paper, all the twelve (12) ICD's wells plus the two (2) intelligent wells post-execution production analysis will be discussed. A post-mortem of the effectiveness of such innovative solution is performed to assess the production impact on SS field with some wells' production data available more than two years'. From the good success case studies of the high-performance wells, post-production profiles have indicated a huge transformation towards realising more oil incremental while reducing the cost of handling less water and gas. However, lesson-learnt can also be drawn from a few of the so-called "Could-have-been-better-performers". This is then highlighted with the way forwards plan to both further sustain production and look-ahead into applying the best practices of such technology pilots to other asset development and conceptual. This paper could provide an eye-opening insight into some of the best-kept value of downhole flow control application with actual production impact and data analysis.
Mechanisms of Generating Overpressure and Its Influences on Super-Low Permeability Reservoirs of Upper Es4 Member, Chexi Depression
Authors: Zhenyu Zhao , Yanru Guo , Qing Zhang , Hong Liu
Published: May 2016

By means of analyzing super-low permeability reservoir of upper Es4 member in Chexi depression into sedimentary microfacies, diagenesis, reservoir porosity and permeability and testing geochemical data, the mechanisms of generating overpressure and its influences were discussed. The results show that:The reservoir, being evaluated medium-low porosity and super-low permeability, is disadvantageous to oil & gas exploration and development, as lithology is argillaceous fine sand, porosity is 10% ~ 20% and permeability is less than 10×10-3µm2 in general;The principal mechanism of generating overpressure is disequilibrium compaction, and the secondary is mineral diagenesis;The overpressure can effectively inhibited formation temperature to increase and diagenesis process;In overpressure wells section, the secondary porosities and fractures are preserved during mesodiagenesis stage and telodiagenesis stage, which are favorable to oil and gas exploration and development;In study area, it is not a positive linear relationship between oil production capacity and formation pressure coefficient, as high production capacity corresponds to the pressure coefficient of 1.2~1.3.

With increasing production capacity of the global oil and gas and exploring most oil and gas reservoirs year by year, the influencing factors of super-low permeability reservoirs was also more and more attention [1–3]. Since the 1950s, through the geologic simulations and the typical overpressure basin studies, many scholars analyzed that overpressure could preserve the primary and secondary porosity to improve reservoir preformation in two kinds of mechanisms with physical and biochemical actions [4–6]. In development process of overpressure reservoirs, the overpressure fluid will change rock stress to make the elastic and plastic deformation, so as to reduce the porosity and permeability [7–8]. Therefore, overpressure constructive and devastating effects on reservoir properties still need further clarification.
Creating Economic Value from Porosity and Permeability: Integrating Geology, Reservoir Engineering and Commercial Factors for Evaluation of Unconventional Resource Opportunities
Authors: Steffen Kurt , Hood Ken
Published: May 2016

Comprehensive evaluation of unconventional resource opportunities requires the integration of geologic, engineering, timing, competition, and fiscal factors that influence the commerciality of a project. Although unconventional resources such as Shale Gas, Tight Gas, Tight Oil, and Coal Bed Methane commonly are treated as continuous accumulations, the subsurface and operational considerations that control commerciality vary spatially throughout the play. Evaluation of these resources requires an approach that honors the "continuously varying" nature of the hydrocarbon accumulations. Unconventional resources, particularly natural gas, can have significant influence on local markets. Such effects can challenge areas within plays that have less favorable geologic quality, operational challenges, or costs. As a result, early identification of the geologic sweet spot and optimal project required to exploit the resource is crucial.
Wulalike-Kelimoli Petroleum System of the West Margin of Ordos Basin, China
Authors: Xu W. , Guo Y. , Liu J. , Gao J. , Zhao Z.
Published: May 2016

The Ordos Basin, which is situated in the north part of China, is one of the largest basins in terms of natural gas resources in China. Natural gas accumulation from marine source rocks in Ordovician was found recently in the west margin of Ordos basin. The purpose of this paper is to describe the geological conditions of gas accumulation in the Ordovician in the west margin of Ordos basin and the identification of the Petroleum System.

The marine source rocks, occurred in the Kelimoli and Wulalike formations of Ordovician which consist of shale, mudstone and marlstone, are mainly distributed in the west margin of Ordos basin where sedimentary environments are deep ramp faces. The thickness of strata ranges from 20m to 200m, with the TOC ranges from 0.19% to 4.55%. The kerogens are dominated by type I or II and the thermal maturity is mostly in the range of 1.4 to 2.8% Ro.

Limestone bedding karst cavity reservoir in Kelimoli formation constituted the main space for the gas accumulation. The bedding karst cavity reservoir, with the average porosity between 4% to 6% and the permeability between 0.1×10-3µm2 and 2.0×10-3µm2, is the main gas reservoir. The limestone bedding karst cavity reservoir mainly distributed in the west with the thickness between 60m and 170m and is interbedded with the source rock while the dolomite reservoir mainly distributed in the east.

The overlying coal-bearing strata which are wide continuous distributed prepared the good cap rock with high quality. The Kelimoli limestone is the main reservoir rock. The Wulalike mudstone is not only the source rock but also good local cap rock. The overburden rock includes the late Carboniferous, Permian and all the Mesozoic and Cenozoic. Lithology lateral change in Kelimoli formation is the main reasons to control the traps, and structure movements are the minor reasons for traps. The vitrinite reflectance values and the homogenization temperature of fluid inclusions suggest that the onset of the oil generation started in the late Jurassic and gas in the early Cretaceous.
A New Analytical Model to Predict Gas Rate Volume Measurement Through Well Head Chokes
Authors: Leal Jairo , Al-Dammen Mohammed , Villegas Ruben , Bolarinwa Simeon , Aziz Abdul , Azly Ahmad , Buali Mustafa , Garzon Francisco
Published: May 2016

Historically, choke gas equations have been extensively used for gross estimation about gas volumes. These analytical models give a quick evaluation on gas volume but also face some serious limitations on specific topics like water presence, excessive gas velocity and pressure drop, limited differential pressure and high condensate to gas ratios. Many different efforts have being completed using several analytical models which can be applicable under certain conditions.

This paper details a new predictive model for estimating the gas rate measurement through wellhead chokes and also covers all efforts for Saudi Aramco to get a single digit error on estimating gas rates for Ghawar gas condensate producers by implementing this new analytical model.

Additionaly, the application of this new gas equation covers a wide range of operative conditions as well as gives great benefits since perspective of:Reducing gas allocation errorImproving gas estimation while comparing with regular test separatorIdentifying well optimization opportunitiesGetting cost saving while minimizing use of conventional well-testingValidating venturi meter calculationsImproving well performance and diagnosticKeeping surface equipment under optimum operative conditionsMinimizing erosion while providing optimum gas velocity calculations

The main objective of this paper is sharing this equation with Gas Producing Engineering Worldwide community and covering methodology of implementation as well as sharing practical field application cases.
Productivity Decline Due to Fines Migration (Modelling and Field Case)
Authors: You Z. , Badalyan A. , Bedrikovetsky P. , Hand M. , Jenson D.
Published: May 2016

High formation damage, including that induced by fines migration has been reported in numerous geothermal projects. The attaching electrostatic forces acting on fines are weak at high temperatures if compared with drag and lifting forces, which detach the particles from grain surfaces. Migration of lifted fines results in their straining in thin pores preferentially near to well, causing severe permeability and productivity decline. A mathematical model has been developed, based on recently developed theory of particle detachment in suspension flows. Solution for predicting well productivity is obtained. The model is validated by comparison with the field data from geothermal well A in Australia. Productivity decline due to fines migration is more likely to happen in high temperature geothermal reservoirs if compared with conventional aquifers or oil and gas fields.

Introduction

Productivity decline as well as induced formation damage due to fines migration in conventional oil and gas reservoirs has been widely reported since 1960s, and is still a hot topic these days (Muecke, 1979; Lever and Dawe, 1984; Sharma and Yortsos, 1987; Sarkar and Sharma, 1990; Khilar and Fogler, 1998; Tiab and Donaldson, 2004; Civan, 2007; Geng et al., 2010; Rosenbrand et al., 2012). The phenomena including fines mobilisation, subsequent reduction of reservoir permeability and formation damage have also been observed during drilling, discharge, injection and production stages in the geothermal wells. However, the comprehensive analysis of formation damage specific for geothermal reservoirs is not available yet.

Flow of suspended fine particles with particle capture, detachment and rock clogging takes place in porous media (Fig. 1), during the propagation of particles, bacteria and oil droplets in reservoirs, filtrate invasion into formation while drilling, injection and discharge of water in geothermal fields, etc. The particles at the rock surfaces are subject to the electrostatic force Fe, drag force Fd, lifting force Fl and gravitational force Fg (Fig. 1). The drag and lifting forces tend to detach the particle from the grain surface while the electrostatic and gravitational forces attach it. It is assumed that at the moment of leaving the solid surface, the particle rotates around the neighbouring attached particles or around a spike of the surface ((Fig. 1b,c). Therefore, the condition of mechanical equilibrium of a particle on the grain surface is the balance of the detaching and attaching torques exerting on the particle (Freitas and Sharma, 2001; Bedrikovetsky et al., 2012). At high flow velocity near the wellbore, the detaching torque on the particles may exceed the attaching torque. Thus, the particles can be released and brought to the suspension flow as a result. The migrating particles may be further captured at thinner pore throat, or attached to the pore wall (Fig. 2), depending on the particle and pore geometry and hydrodynamic conditions.
Explicit Modeling of Hydraulic Fracture Propagation in Fractured Shales
Authors: Savitski A.A. , Lin M. , Riahi A. , Damjanac B. , Nagel N.B.
Published: May 2016

Recently a combined application of two technologies, horizontal drilling and multi-stage massive hydraulic fracturing (HF) has made vast resources of shale gas commercially viable. The HF is a well-established reservoir stimulation technique, which has been developed over the last half century. There are reliable tools for designing HF in conventional reservoirs, in which a planar HF is assumed.

On the contrary, in shale gas fracturing, micro-seismic observations have illuminated a complex internal structure resulting from the interaction of the induced hydraulic fractures with natural fractures. It is widely speculated that the stimulated natural fractures make a significant contribution to the gas production.

The mechanics of the interaction between multiple fractures during a HF treatment is very complicated. In this paper we present the results of state-of-the-art modeling of an explicit interaction between a propagating hydraulic fracture and a statistically generated discrete fracture network. A sensitivity study reveals a number of interesting observations including importance of initial fracture conductivity for growth of the fracture system, effect of the dilation angle on the generated conductivity and net pressure and uneven distribution of fracture aperture that is critical for proppant placement.

This work strongly links the production technology and geomechanics and suggests an approach for modeling and designing HF treatments in unconventional shale gas plays.

Introduction

Natural gas and light oil production from shale formations has become the focus of much attention in the past decade. The economic success of the development of these unconventional resources owes to a combined application of two key and well-known technologies: horizontal drilling and multi-stage hydraulic fracturing (King, 2010). The horizontal wellbore sections, commonly with length ranging from 750 m to over 1600 m, are either cased and cemented or isolated with packers to enable multi-stage fracture stimulation (Cipolla, 2009). Hydraulic fracturing (HF) is a well-established reservoir stimulation technique, which has been developed over the last half century. It is not an exaggeration to say that in ultra-tight reservoirs such as shales the connected reservoir conductivity is created in the process of hydraulic fracturing and that enables any measurable hydrocarbon production.
Modeling and Performance Interpretation of Flowing Gas Composition Changes in Shale Gas Wells with Complex Fractures
Authors: Freeman C.M. , Moridis G.J. , Blasingame T.A.
Published: May 2016

Limited attempts have been made to model shale gas reservoirs on a compositional basis. Multiple distinct physical phenomena influence the behavior of reservoir fluids in shale, resulting in measurable compositional changes in the produced gas over time. These phenomena include differential desorption, fractionation via phase change, and preferential diffusion. To address these phenomena, we have developed a compositional numerical model which describes the coupled processes of diffusion and desorption. We have also developed a tool for generating simulation grids capturing fracture geometries of realistic complexity. By combining the physics of flow in complex fractures with diffusion through nanopores, we show how gas composition changes during production. We identify and illustrate signature trends in the flowing gas composition according to our model. In addition, we present a workflow for the integration of measured gas composition data into traditional production data analysis. We prove that the onset of various transient flow regimes that are unique to shale gas reservoir systems can be identified in the model-based flowing composition data. For example, the transition from fracture-drainage to matrix-drainage can be identified by a characteristic trend in flowing gas composition. Some reservoir properties can be determined through analysis of the compositional shift in the flowing gas. This work expands the current understanding of well performance for shale gas to include physical phenomena that lead to compositional changes for realistic fracture configurations. This work can be used to optimize fracture and completion design, improve well performance analysis and provide more accurate reserves estimation. In this work we develop a numerical model which captures multicomponent desorption, diffusion, and phase behavior in ultra-tight rocks, we present a grid generation technique which captures the complexity of shale system fractures, and we validation of our interpretations of diagnostic trends.
Operational Challenges in Managing High CO2 Content Gas Production in Peninsular Malaysia Operations
Authors: Hadi Sriyanta , Meri Ambok Malek , Mahadi Ahamd Zulhairi , Abd Ghafar Ezatul Shima , Shariff Din Siti Nurul Aimi , I Fen Soh
Published: May 2016

Peninsular Malaysia Operations (PMO) plays an important role in supplying gas demand throughout the region since the gas business commencement in 1980's. Currently about 600 MMscfd gas is supplied by PMO. At the moment, three non-associated gas (NAG) fields, namely DYG, RSK, and TBC contribute to about 50% of the total gas supply from PMO. Apart from producing NAG, the RSK and DYG fields also serve as network hubs to evacuate gas to the Onshore Gas Terminal (OGT) through two independent gas delivery systems: Joint Delivery System (JDS) and Resak Delivery System (RDS) respectively. The two JDS and RDS gas streams are mixed at OGT and then delivered to the customer processing plant, with a CO2 maximum limit of 8% by mole. Apart from the many operational challenges to sustain gas production, meeting the gas specification proves to be a difficult task, especially for the RDS where TBC gas (with about 30–40% CO2) is to be blended with RSK gas (itself producing about 23% CO2).The TBC gas was put on stream in 2011 and an Acid Gas Removal System (AGRS) was deployed to reduce CO2 content. Prior and upon commissioning of the AGRS facility, feed of CO2 level into the gas network was managed by optimizing the flow rate. This paper describes some major challenges in sustaining the gas production supply and meeting the gas quality requirement. The major operational challenges include subsurface uncertainty and problems, maintaining gas compression reliability, AGRS operations and optimizing the usage of gas pipeline network. To complete the analysis, some commercial aspects are also discussed in the paper.

Introduction

This section consists of two parts:overview of gas business in Peninsular Malaysia andoverview on RSK/DYG field operations.

The first part would be introducing the gas market in Peninsular as well as the strategy of fulfilling the gas demand. The second part would be describing the RSK/DYG field operations as the focus of this paper.