bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach for the Estimation of a Laterally Variable Anisotropic Velocity Model
Authors: Bacenetti R. , Andreoletti C. , Ferla M. , Panizzardi J.
Published: March 2015

A case history of anisotropic velocity model building on a West Africa (offshore Angola) dataset is proposed. The goal of the project was to improve depth imaging quality, in particular in terms of accuracy of event placement and fault positioning, and also to estimate a reliable velocity model for pore pressure prediction. Seismic data provided evidences of the presence of anisotropy in the area. In order to obtain a robust and reliable estimation of Thomsen's anisotropic parameters, we applied two independent methods in parallel: the first one, used as reference, is based on the standard time-domain approach [1] whilst the second one works in depth domain and applies the migration velocity analysis principles [2]. The two approaches resulted in coherent estimates of Thomsen's parameters but the depth domain approach is preferable because of its integration in the imaging workflow: the definition of the vertical velocity (and, therefore, of Thomsen's delta parameter) at well locations is univocal thanks to the exploitation of depth stratigraphical markers. The introduction of anisotropy in the model, tightly coupled with an accurate velocity analysis, not only allowed obtaining the correct depth positioning but also a remarkable improvement in imaging quality with respect to both PSTM and the initial isotropic PSDM.
Running Casing in Stands with Automate Casing Drive System - Case Studies
Authors: Lee Chee Wai , Won Keith Shao Wang
Published: March 2015

Escalating rig rates in recent years have resulted in operators looking for faster and safer well construction techniques for all aspects, including casing-running operations. With current trends of wells design pushing the casing seat deeper, reduction of total casing-running time plays a crucial role in minimizing total drilling cost. One performance improvement objective is running casing in double-joint or triple-joint stands.

Conventional casing running is known as a high-risk process, involving considerable manual handling on the rig floor. Casing running in stands using the conventional side-door elevators and manual handling by the derrickman on the stabbing board are less efficient and raise safety concerns.

An automated casing-running system has been introduced that can solve the problem of long casing-string handling. This powerful tool minimizes both the rig crew's involvement near the rotary table and personnel working at heights. Casing handling via automation results in a safer casing-running operation and reduces total casing-running time. This versatile system also provides the extra capability of rotating, reciprocating, circulating, and pushing down the casing string through problematic zones to ensure successful installation of the casing at total depth (TD).

This paper will introduce the successful implementation of casing running with double-joint and triple-joint stands using the automated casing-running system, and detail the performance improvements of tripping casing in stands.
Role of Detailed Reservoir Characterization and Lateral Placement on Well Performance in the Marcellus Shale Gas Reservoir
Authors: Shebl M.A. , Nyaaba C. , Yalavarthi R.
Published: March 2015

Development of a shale gas reservoir is dependent on petrophysical parameters indicating gas availability and the success of well completion in accessing this gas. To evaluate shale gas reservoirs it is essential to understand and evaluate the reservoir's heterogeneity and its effect on its rock quality. The benefit is identification of better hydraulically-fracable zones amongst the best reservoir quality rock. Thus this paper illustrates how petrophysical analysis, in conjunction with geomechanical modeling, aids in determination of the optimum lateral placement and fracture design for a successfully producing well.

Petrophysical analysis was performed to determine the reservoir quality, Original Gas-in-Place (OGIP) and the geomechanical property distribution. Based on the distribution of these petrophysical properties, different lithofacies were identified; potentially fracable zones and fracture barriers were predicted. Case histories of two wells are presented to demonstrate how detailed petrophysical analysis assists in determining the correlation between lateral placement and well performance. The first well was drilled in a good reservoir quality interval with the lateral placed in brittle zone in-between rocks with high gas content. As a result, it had good performance with a higher linear transient productivity index. The other well was drilled in a bad reservoir quality interval with the lateral placed in a brittle zone with low gas content and lower performance.
First Steps of Channel Fracturing in Russia Set New Directions for Production Increase of the Oil Fields
Authors: Yudin Alexey , Enkababian Philippe , Lyapunov Konstantin , Nikitin Alexey , Sitdikov Suleyman , Serdyuk Svetlana , Serdyuk Alexander
Published: March 2015

Channel fracturing technique changes the concept of proppant fracture conductivity generation by enabling hydrocarbons to flow through open channels instead of the proppant pack. The new technique is based on four main components: proppant pulsing at surface with fracturing equipment and software, a special perforation strategy, fibrous material to deliver stable channels, and a set of models to optimize channels geometry.

Channel fracturing in Russia's oil fields began in 2008 as field testing operations in tight collaboration with the development team. Full-suite logs provided geomechanical models and ensured fracture channels optimization. An important result of those first treatments was long-term channels stability. The treated wells continue to show stable productivity over a four-year period. As of today, more than 90 channel fracturing treatments have been pumped in Russia with no screen-outs. A very low screenout risk has become one of the most important advantages of the technology; the fibers make fluid more stable while the presence of clean pulses around proppant structures ensure bridging-free flow. As the channel's conductivity does not depend on proppant size to hold channels open, treatments can be performed with smaller proppants (20/40 or 16/20 mesh) instead of larger proppants (12/18 mesh) that have an increased risk of screenout.

In combination with abrasive jetting perforations, channel fracturing has proven to be an efficient stimulation solution for Russia's multi-layered reservoirs. This completion technique ensures proper flow distribution into perforation clusters according to the channel's specific requirements. It also allows reliable proppant admittance through jetted caverns.

Channel fracturing increases the effective half-length with increased treatment size. A considerable number of channel fracturing jobs with proppant mass equal to standard fracturing designs have been performed—significantly increasing channeled length and providing better production in low permeability (1 to 3 mD) oil reservoirs. Based on production analysis of stimulated wells in five different areas, a correlation between incremental channel fracturing productivity over the conventional stimulation technique and kH value of the formation can be made: the higher the kH the more significant the advantage of the channel fracturing is in oil wells.
Evaluation Techniques of Reserves for Heavy Oil and Oil Sands
Authors: Wensong Huang , Heping Chen , Zheng Meng
Published: March 2015

With the annual growth of development scale and production, the research of heavy oil and oil sands become more and more important. Due to the characteristics of heavy oil and oil sands, the degree of reserves recovery is restricted by development mode. So there is a big difference in classification criterions and evaluation techniques of reserves in the world. In this paper, using the major heavy oil and oil sands accumulation areas —Venezuela heavy oil belt and Canada oil sands as example, we analyse the reservoir characteristic of heavy oil and oil sands, and then discuss the classification and evaluation techniques of reserves suitable for different development modes.

The heavy oil belt in Venezuela and oil sands in Canada are all characterized by huge thickness, middle-fine sandstone, loose cementation, high porosity and high permeability. To adapt different development mode, we establish corresponding evaluation criterions for reservoir, including porosity, permeability, shale content, saturation, barrier and interbed, the thickness and width of continuous oil layer and so on. We classify the reserves as OOIP, economic reserves, reserves for horizontal well, reserves for steam flooding (SF)/ cyclic steam stimulation (CSS) and reserves for SAGD. Using logging and geophysical techniques, we evaluate and classify the reserves.

1.Introduction

Heavy oil and oil sands are characterized by shallow buried depth, large thickness, huge reserves and unconsolidated structures. Because crude oil has high viscosity, conventional vertical wells generally have no or extremely low productivity. Currently, these reservoirs are predominantly developed by horizontal wells in two stages: cold production and thermal production. All these conditions have presented new requirements on contents and methods of reserve evaluation. In this essay, through study on reservoir features and corresponding development techniques for heavy oil in Venezuela and oil sands in Canada, we put forward reserve assessment methods and techniques by class for various development modes.

2.Reservoir evaluation and selection criteria for heavy oil and oil sands development

Currently, cold production (CP) is the prevailing development method adopted for heavy oil in Venezuela, at the same time, cyclic steam stimulation (CSS), steam flooding (SF) and SAGD have been tested. Oil sands in Canada are mostly developed by SAGD and open mining. A series of reservoir selection criteria have been proposed to cope with requirements of different development methods with horizontal wells on oil layers (Table 1).
A Meshless Surface-Fitting Method for Fault Detection
Authors: BaDughaish F.A.
Published: March 2015

Seismic data adequately reveal subsurface geological structures but require special analysis techniques to detect subtle geological features such as faults. Detection of faults in seismic data is, for the most part, a qualitative procedure requiring proper data interpretation, sometimes leading to a source of ambiguity for the real fault location. Quantitative techniques based on seismic attribute analysis are employed to reduce this ambiguity and are the focus of this study.

A new numeric method based on the meshless Moving Least Squares (MLS) is used to enhance the fault detection technique introduced by Gibson et al. (IEEE 43:2094–2102, 2005). This method generates a set of points called seed points, which lie on the fault surface, by examining the eigenvalues (i.e. the local covariance matrices of the structural tensor) of cubes from the data. Next, the seed points are grouped together using the neighborhood relationship (compatibility) between every two individual points. Finally, the seed points are used to create the final surface. A meshless technique is then used to fit a surface through these points. Fitting the meshless surface is found to be more efficient than traditional mesh-based techniques.

This study also compares various mesh-based and meshless techniques. It is found that meshless methods have better accuracy, are more efficient in determining point connectivity on-the-fly at run-time, and avoid mesh-alignment issues. Also, traditional surface fitting techniques divide the fault surfaces into smaller surfaces (a common problem called over-segmentation), which is less of a problem using meshless methods.

The MLS-based meshless surface fitting approach has shown promising results with potential benefits to seismic data interpretation and geological structure delineation. This method has not yet been adopted in the oil industry. However, the results have shown great potential for improving the quality of seismic interpretation in general and fault detection in particular.
Successful Fracture Stimulation in the First Joint Appraisal Shale Gas Project in China
Authors: Jin Liang , Zhu Changlong , Ouyang Yong , Zhou Ming , Qu Qingguang , Li Fei , Yuan Roger , Wu Chris , Zhang Zhiyi , Wang Yan , Dwan Fa , Vitthal Sanjay , Wang Shiqian
Published: March 2015

This paper discusses fracture stimulation in the first joint venture shale gas project with foreign companies in China. Shell China Exploration and Production Company (SCEPCO) is jointly appraising the shale gas play with partner PetroChina. The block is in Sichuan, China. The target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low, in the range of 100–300 nano-Darcy but rich in natural fractures. Hydraulic fracturing has been proven a key to enhance the production by effectively connecting natural fractures and providing a path for the gas to flow into the wellbore.

"Every shale reservoir is different." The joint working team is facing specific challenges in this play:Understanding of reservoir based on the study of geology, petrophysic, geomechanics.High wellhead treating pressure due to high formation stress and pore pressure.Deep wells - some deeper than 3,500m TVD.Fluid system and proppant type and size selection.Fit for purpose treatment size and pump program.Connection between wellbore and formation through the fracture.Horizontal wells - Stimulation interval selection, stage spacing, perforating strategy.Unknown fracture geometry - only 1 microseismic was applied in a horizontal well.

Two vertical wells and three horizontal wells have been fracture-stimulated to date. The team has gained valuable experience and made significant improvement step-by-step and well-by-well. This paper discusses how a collaborative approach was applied to the completion of the shale gas wells during appraisal. Initial production test results of the wells have been promising. This is a significant step to unlock the potential of shale gas resources in China and help meet the country's energy needs.
Marine Seismic Acquisition at Scott Reef, Western Australia: Minimising Environmental Impacts in a Sensitive and Remote Location
Authors: Taylor Mark , FitzPatrick Jeremy , Weiss Ralph
Published: March 2015

Introduction

The Torosa gas field forms part of the proposed Browse LNG Development1, a project to commercialise three gas and condensate fields located on the outer continental shelf of northwest Australia, approximately 400km north of Broome. Two of these fields (the Brecknock and Calliance fields) are located in deep water and have been fully imaged by modern 3D towed streamer seismic surveys. However, the Torosa field partly underlies Scott Reef, which consists of two coral atolls separated by a deep channel.

The only permanently emergent land at Scott Reef is a small sand cay (Sandy Islet - Figure 1), although the reef crests of both atolls are exposed at low tide. Outside the reefs the seafloor drops away rapidly, with water depths of about 350m to the east, increasing to more than 1000m to the west. South Scott Reef lagoon is open to the north, with water depths increasing to about 50m before deepening abruptly into the channel between the two reefs. North Scott Reef lagoon is shallower - generally less than 25m - and is connected to the ocean by two narrow channels. Semi-diurnal tides with a range of up to 4.6m produce strong tidal currents in and near these channels. Small, steep-sided coral heads, or 'bommies', are common throughout the lagoons, especially in water less than 25m deep.

Since 2005 Woodside Energy Ltd has acquired five seismic surveys over the Torosa field using a range of acquisition techniques. These surveys were important steps towards acquiring full seismic coverage over the Torosa gas field (Figure 1). The first of these surveys, the Torosa 3D marine seismic survey (MSS), was a conventional deep water 3D towed streamer marine seismic survey acquired in late 2005, which covered the deep water portion of the Torosa Field located northeast of Scott Reef. Four further seismic surveys have extended the area of 3D seismic coverage into the south Scott Reef lagoon and across north Scott Reef.

Prior to commencing the seismic programme over the shallow-water parts of the Torosa Field, Woodside carried out an extensive airborne bathymetric survey of the entire Scott Reef system in early 2006. Additional bathymetric surveying was undertaken to fill some data gaps within the airborne bathymetry survey, resulting in a comprehensive, highly-detailed data set on a 4m2 grid with vertical resolution of 0.1m covering both north and south Scott Reef to depths of about 50m. Woodside also undertook extensive metocean work including both tide and current modelling and model verification. These datasets were critical for the planning of the subsequent seismic surveys.
Effective Well Integrity Management in a Mature Sour Oil Field
Authors: Almukhaitah Abdulaziz A. , Haldar Surajit
Published: March 2015

Maximizing the productive life of wells and minimizing the risk of uncontrolled release of reservoir fluid over the entire life cycle of the wells are the major objectives of any E&P company. Therefore, managing well integrity has become as important as managing reservoirs without compromising the safety of personnel or the harmony of the environment, and at the same time protecting valuable assets for a prolonged life.

One of the large mature onshore oil fields of Saudi Arabia is producing sour crude oil that multiplies the well integrity challenges. A stringent well integrity surveillance and maintenance program is followed for this field to ensure the integrity of every individual well. The program, essentially developed for Saudi Aramco onshore oil fields, is a proactive problem prevention-based approach. Under this program, any well integrity related problem can be predicted through a structured preventive diagnosis and maintenance schedule for both wellhead and downhole integrity to assure well integrity that verifies and confirms the status of wells with suspect integrity. The program is governed by the operating standards and guidelines for maintaining the well integrity parameters, ensuring safe well operations and securing uninterrupted well productivity and injectivity. The program also emphasizes the requirement of barriers during normal operations, unscheduled well interventions or when shut-in for safety and environment protection.

This paper describes the process for efficiently managing well integrity throughout the development life cycle with a particular focus on production operations and the well maintenance phase. The objective of this paper is to provide an overview of the rationale for following this structured program and the realized benefits.
Fluid-Level Monitoring Using a Distributed Temperature Sensing System During a Methane Hydrate Production Test
Authors: Sakiyama N. , Fujii K. , Pimenov V. , Parshin A. , Yamamoto K. , Wright J.F.
Published: March 2015

Temperature profiles and their transient behaviors obtained using a distributed temperature sensing (DTS) system were measured while monitoring wellbore fluid levels during a methane hydrate production test. The temperature data were obtained in 2008 as part of the JOGMEC/NRCan/Aurora Mallik 2007–2008 Gas Hydrate Production Research Well Program.

Methane hydrate is known to be stabilized under low-temperature and high-pressure conditions. In the Gas Hydrate Production Research Well Program, a depressurization method using an electric submergible pump (ESP) was employed to dissociate the hydrate in the reservoir. For recovering the produced gas and fluid without resynthesizing the hydrate after the dissociation, it was essential that the temperature of the produced fluids flowing up the tubing be controlled.

According to our numerical temperature simulation, the annulus fluid level around the tubing is one of important factors that govern the tubing fluid temperature during the methane hydrate production. If the annulus fluid level is high, the tubing fluid temperature becomes so low that methane hydrate can potentially be formed inside the tubing; thus, understanding fluid levels during methane hydrate production is important for flow assurance as well as bottomhole pressure control. The conventional method for estimating fluid levels in a wellbore employs an acoustic wave reflection technique; however, the accuracy of the survey is subjected to assumption of an acoustic velocity which depends on pressure, temperature, and gas types. On the other hand, estimating fluid levels with a DTS temperature profile is thought to be a more direct method. Although it is not widely known, several papers indicate that the feasibility of estimating fluid levels with the DTS system when the fluid level is static.

In this paper, we demonstrate the feasibility of estimating dynamic fluid levels using a DTS system. The dynamic trend in estimated fluid levels with the DTS system shows qualitatively good agreement to that estimated with the pressure on the completion assembly and the pressure at the casinghead. The difference in fluid levels between the DTS temperature-based and the pressure-based methods quantitatively explains a void fraction in the two-phase flow of the fluid and the gas. The analysis presented in this paper is based on field data collected during methane hydrate production, but it is potentially applicable to any conventional production scheme that employs artificial lift.
An Integrated Approach of Sequence Stratigraphic Study in Southwestern of Malay Basin
Authors: Wei Chen Harry Wong , Ab. Aziz Sham Shukriah , B Mahmud Othman Ali , Pendkar Narender , Bt Sapri Dayang Haspariah
Published: March 2015

This paper presents the results of an integrated sequence stratigraphy approach using seismic, well log and biostratigraphic data to build sequence stratigraphic framework and its implication in petroleum system understanding for the southwestern part of the Malay Basin. Seismic data were used to interpret third order Sequence Boundaries (SB) and Maximum Flooding Surfaces (MFS) based on reflector terminations. Well log analyses were carried out to support the interpretations and were cascaded down to define the third order sequences and associated system tracts (LST, TST and HST). Biostratigraphic data were also used to validate the SB, MFS and the paleo-environments.

This study has subdivided the sedimentary successions into six 3rd order sequences namely Sequence 1 to Sequence 6. Each of the sequence is bounded by sequence boundary, which has been calibrated with the Malay Basin Chronostratigraphic Chart (PETRONAS, 2007).

Two source rocks are present for the study area- the deeper synrift section with source rocks deposited in a lacustrine environment (Late Oligocene age) and the shallower source rock deposited in a marine inner neritic environment (Early Miocene age). The migration pathway for the deeper section is through faults, and from lateral migration for the shallow section. The study also indicates that the potential reservoirs are thinning basinward (southwest to northeast). The potential reservoirs are interpreted to be the fluvial, lacustrine and shallow marine sands. Data from several key drilled wells suggests that reservoir is at low risk in the sand-prone areas of the southeastern part compared to the northern part which is more shale-prone. Based on the present study, it is inferred that trap integrity is the main risk for petroleum system. While a good top seal is provided by the main regional shales in deeper section, the seal at the shallow sections are from thin and discontinuous intra-formational shales that are present in every sequence. The presence of younger faults cutting through the reservoir may cause the potential for hydrocarbon leakage.

The present study has identified five potential plays and also established the regional sequence stratigraphic framework in southwestern of Malay Basin.
Use of Chemical Foamers to Deliquify the Loaded Wells in Sebei Gasfield
Authors: Zhi-jian Liu , Chunming Xiong , Wenkui Li , Jun Li
Published: March 2015

In Sebei Gasfield, liquid loading in the well bottom has seriously impacted the well productivity. Use of chemical foamers to deliquify the loaded wells has testified to be one of the most effective mothods. However, it is always challenging work to select the most compatible foamer. Besides, not all wells will respond successfully to the foamer treatment. Thus, tedious work has to be done to screen the potential wells. In this paper, a novel efficient foamer has been developed using the Response Surface Method. It provides a new way to formulate foamers for gas well deliquification. It proves both time and labor saving. Using historical well data and from discussion with the operator, an understanding of the candidate wells can be gained. The criteria for selecting a ideal candidate well for foamed lift has been fully investigated. We find the most suitable flow regimes for foamer treatment are slug flow and annular flow. Then, we optimize the usage of foamer with the aid of mathematic model. The foamer injection pattern, such as intermittent injection and continuous injection, has also been discussed. For different well condition, different injection pattern should be applied. This paper also includes several field trial cases.
Real-Time High-Resolution LWD Images Used to Navigate a Carbonate Reservoir
Authors: Janwadkar Sandeep Shashikant , Murell Paul , Thomas Mark
Published: March 2015

The Permian basin of West Texas is one of the most mature and prolific oil provinces in the US, and continuously evolves in its production potential via the drilling of horizontal wells. A vital element to accelerate ROI is to accurately place the wellbore in the target formation. Determining and identifying the zone of interest within the carbonate interval and then navigating within it with conventional LWD technology has become a major challenge. To overcome these challenges, real-time high-resolution LWD images were proposed. Azimuthal gamma ray and multiple propagation resistivity measurements were used to determine bed dip, correlate position within the reservoir and indicate formation porosity variations. Advanced LWD imaging tools provide visual confirmation of steering up and down within the reservoir and identify structural information, porosity changes, rock type, faults and the location, density and type of fractures. This paper provides examples of reservoir navigation techniques along with the increased precision provided by imaging tools. Previously undetected faults, brecciated intervals, and fractures are identified. This enables a more precise completion design that reduces risk and increases production. Using this method, the percentage of the lateral interval in zone was increased to 100% from 77% in an offset well. Images of lateral variations in the formation will be presented. This information was used to optimize the completion design and is invaluable in the planning of future wells. LWD images are used to more efficiently drain the reservoir by providing the necessary information to stay in the target zone during longer intervals and assist completion optimization. LWD images can also be used to help explain production variances commonly observed between wells targeting the same interval.

Geological Background

The Permian Basin is a sedimentary basin largely contained in the western part of Texas and the southeastern part of New Mexico (Fig. 1). It is so named because it has one of the world's thickest deposits of rocks from the Permian geologic period.

The Permian Basin was deposited from Ordovician through Mississippian time, and is deepest just west of Midland. It was uplifted at the end of the Devonian and early Mississippian periods. Tectonic activity at the end of the Mississippian period created the Midland Basin to the east, the Delaware Basin to the west and the Val Verde Basin to the south. During the Pennsylvanian and Wolfcamp periods, the basin was favorable to reef growth and the building of shelf margins on the edges of the Delaware and Midland basins. The last major geological development was the Permian Reef Complex, which developed on the border of the Delaware Basin. (J. Michael Party 2012)
Development and Application of Horizontal Well Drilling Technologies with Liaohe Oilfield's Characteristics
Authors: Xun Chen
Published: March 2015

On September 13, 2011, China Petroleum Daily published an article titled '1,000 Horizontal Wells Support the Stable Production of 10Mt/y of Oil in CNPC Liaohe Oilfield' on the front-page. This marked a historical breakthrough in large-scale application of horizontal wells in Liaohe Oilfield. Rather than deliberately pursuing the cutting-edge technology, the development and application of horizontal well drilling technology was based on practical experience of oil & gas exploitation, predominantly lead by conventional horizontal well technology. The development and application of horizontal drilling technology also focused on solving the technological difficulties of multilateral and complex wells. Extensive efforts were made to develop sidetracked horizontal wells in the exploited zone. In the development and application process, ten major horizontal well drilling technologies with Liaohe's characteristics were developed, which included MRC fishbone well, SAGD paired horizontal well, multilateral well, complex well, sidetracked horizontal well, and horizontal & underbalanced drilling integrated technologies.

In addition to an overview of horizontal well drilling technologies with Liaohe's characteristics, the paper also presents achievements of industrial application of horizontal well technology in many areas, such as new block development, heavy oil development mode transformation, secondary development of old oilfields, evaluation and development of hard-to-recover reserves, progressive exploration etc.
A Comparative Analysis of the Contractual and Regulatory Framework of the Oil Industry: Global Changes and Practices
Authors: Shivsulabh Nambiar Aiylath Kutteri , Singh Arshdeep
Published: March 2015

Inception and General Principle of the paper:

The oil and gas industry is an ever shifting paradigm with new happenings which is not only represented through its exploration practices, the inception of new technology, the corresponding implementation of this technology, but is also represented by subsequent and corresponding changes in the techno legal framework as well, which is also needed to be fully appreciated in order to understand the global demand of petroleum and its subsequent by-products which clearly are the driving force of any economy today, hereby enabling even the weakest of countries to determine the political, economic and trade related fate of other Developed countries.

Application and Significance of the Proposed research paper:

The research paper attempts at a comparative analysis between the various contractual regimes with respect to oil exploration and the subsequent production between developed countries such as USA etc. and developing countries such as China, India while also tracking the subsequent changes and global practices in other oil rich countries such as Iraq, UAE etc. who invariably shape the oil and petroleum needs of various countries.

During this course we shall subsequently study successful operations engaged in various models by different countries such as Consessional models, Production sharing arrangement, joint ventures, Service agreements etc., Hereby manifesting and displaying various approaches taken by carious countries, analyzing the same and understanding certain constraints which can/could have been rectified.
Wag Injector Wells: How Intelligent Completion Technology Could Impact on Project Economics
Authors: Di Vincenzo Stefano
Published: March 2015

Nowadays WAG (water alternate gas) injector is considered a new frontier for subsea field with injectors or disposal wells in order to minimize CAPEX and obtain same benefits on field substain.

Looking forwards to forthcoming subsea development, to implement this technology has been considered a must in order to reduce the number of wells dedicated to injection and reduce subsea facilities layed for injection both gas and water. Company is going to develop field in Angola and Nigeria, where oil has different characteristics but with the same constrains related to reservoir pressure maintenance.

This abstract shall consider a study performed by headquarter related to the possible scenario accepting WAG injection using intelligent completion technology and the relative risk analysis. This technology for the company is considered a key choice in order to complete, partialize and control flowing in different layers, with different pressures and different characteristics. Conscious of this ability engineering center decided to move in this direction (more or less one years ago in 2010) and started a dedicated detailed study to consider Angolan field.

The field have a water depth and environment with 1,500 - 2,000 m of water depth.

The goal of the project will be achieved a cut off 50% of the CAPEX related to injectors in both fields, at the same time considering also interface with subsea facilities and surface facilitites. Abstract aims to show what is the impact in terms of economic, evaluated on this project, beginning by base case of injectors dedicated for each level, to final project approved and actually in execution. Terms of comparison will be the delta CAPEX, NPV and IRR of both projects.
Technologies Unlocking Unconventional Gas Resources - Field Case Studies from Northern America and China
Authors: Yu J. , van Gisbergen S. , Dwan S.F. , Yuan R. , Hackbarth C. , Shi S. , Lambrecht J.
Published: March 2015

This paper highlights selected subsurface technologies that are the key contributors to the success in exploring and developing unconventional resources in North America and now elsewhere. Illustrative field examples are presented which have applied these technologies, along with their integrated workflows and best practices, covering a) advanced seismic solutions for unconventionals sweet-spotting; b) improved modelling and numerical simulation software for better hydrocarbon charge prediction and EUR/production forecasts; and c) advanced tools for real-time downhole fracture/production monitoring. Successful field case studies demonstrate how applying advanced techniques may result in reducing lifecycle costs, maximising recovery and minimising environmental impacts in the process of exploring and developing unconventional gas resources. Rapid sharing and replication of new technologies and best practices globally (e.g. from North America to China) will be a key enabler to appraise and develop more resources.

Introduction

Tremendous unconventional gas resources have been estimated in China. For commercial development of such resources, fit-for-purpose technologies are required to address the technical challenges which may be specific at different project phases. In exploration and appraisal phase, the key challenges are 1) identification of the most prospective area 2) characterization of the subsurface and 3) rapid determination of the well productivity and estimated ultimate recoverable (EUR). Some of the latest technologies, successfully applied in unconventional gas in North America, can be applied to unlock the huge unconventional gas resources in China.
Advanced Cuttings Analysis Improves Reservoir Characterisation and Reduces Operating Times in Shale Gas Drilling Project
Authors: Carugo C. , Malossi A. , Balossino P. , Galimberti R. , Gioacchini L. , Rivolta F. , Previde Massara E. , Pingitore F.
Published: March 2015

Significant improvements in shale gas reservoir characterization have been recently obtained by means of detailed geochemical and mineralogical analysis on cuttings and cores directly at wellsite using the combined application of different technologies. These technologies include: X-ray diffractometry for mineralogy, X-ray fluorescence for rock chemical (elemental) composition, TOC analysis for Total Organic Carbon measurement and Pyrolysis for source rock characterization (Hydrogen Index, free oil content, Petroleum Potential & Maturity Index). The analyses, normally carried out in specialized laboratories, have been performed while drilling into a field unit. Dedicated procedures were also defined in order to improve the quality of the cuttings and to optimize the analyses timing to obtain near real time responses. The first field application has been carried out within an exploratory campaign for a shale gas drilling project. The rig site analyses provided in near real time complete geochemical/mineralogical log of the reservoir section. Wellsite analyses have been afterwards validated by laboratories analyses repeated on the same samples, confirming the reliability and accuracy of the rig site measurements. The Advanced Real-Time Cutting Analysis provided a strong support to the drilling operations (selection of the coring point, identification of sweet spot, etc.) resulting in significant time and cost savings in the well target phase and allowed for a reliable quick Formation Evaluation by using the organic matter and mineralogy data to calibrate the wireline logs response. The acquired data were also used to update the geochemical model utilized in the Petroleum System Model performed during the pre-drilling phase for a better understanding of the reservoir during the ongoing exploratory campaign.
Evaluating Wellbore Displacement Efficiency of Post-Slurry Overflushing and Its Effect on Injection Pressure in Waste Injection Operations
Authors: Ji Lujun , Gumarov Salamat , Shokanov Talgat , Anokhin Vyacheslav , Ronderos Julio
Published: March 2015

During the past decade, waste injection (WI) technology, also known as cuttings re-injection (CRI) technology, has been gradually accepted as an environmentally-friendly and cost-effective ultimate disposal method for drilling-related solids and liquid materials. In waste-injection operations, waste slurry is usually intermittently batch injected into appropriately selected subsurface formations. These slurry injections cause injection pressure and in-situ stress to gradually increase as more and more injected solid tends to accumulate in the near-wellbore fracture domain area. Moreover, solids in the leftover slurry can settle out and plug the wellbore during shut-in periods. These issues challenge injection equipments, wellbore integrity, waste domain containment and disposal capacity, and may hinder or terminate injection operations unexpectedly. Therefore, slurry must be properly overflushed from the wellbore and near-wellbore fracture area effectively and immediately. Effective execution and engineering analysis of post-slurry overflushing have become keys for successfully maintaining critical injection assets. A vigilant monitoring of surface, downhole tubing and annulus pressures makes these analyses possible in a timely and proactive manner.

In this paper, post-slurry overflushing with viscous pill and solids-free seawater is numerically modeled for analyzing efficiency of the overflushing and the effects of volume and rheology of the pill on the overflushing in a waste injection well. Moreover, the continuous pressure monitoring in two waste-injection projects in two offshore oilfields provides long-term downhole pressure data. These data were collected and analyzed for instantaneous shut-in pressure (ISIP) after each slurry injection and each post-slurry overflushing, and he effect on in-situ minimum stress and injection pressure was analyzed by comparing ISIP changes before and after overflushing. The studies on ISIP changes confirm the results of the numerical modeling in this paper.

Field studies and modeling results also show that overflushing with the appropriate rheologically-designed viscous pill/seawater sequence can decrease long-term injection pressure buildup rate, avoid wellbore/fracturing plugging and extend ultimate disposal capacity.
Study on Scour Experiment of Bottom-Supported Platform
Authors: Zhao Jing , Wang Shipeng
Published: March 2015

The variation of the seabed may cause the scour around the the foundation of bottom-supported platform in nearshore oilfield, when the platform is fixed on the seabed. For the severe consequences that may cause the slip of platform especially instability of the structure, which need to be paid more attentions in offshore engineering to make it work safely. So it's important and necessary to investigate the characteristic of scour and take effective measures to prevent it. In this paper, scale models are adopted in experiment to study the scour of bottom-supported platform in currents.

It can be observed clearly that the basic characteristic of scour and the evolving tendency of the foundation of the platform through the experiment of two different scales in currents. The area where could be scoured more easily is concluded by analyzing the results. Scour pit pattern and scour depth also can be got through the measurements by ultrasonic topography device. At the same time the maximum scour depth around the foundation of platform can also be inferred based on the scale models theory, which will be helpful for the more sdudy about scour prevention. And it will also have conductive effect for such engineering problem.

Introduction:

Soft soil are widely distributed in Chinese Bohai nearshore region, especially in Dagang, Liaohe and Jidong offshore oilfield, which could induce scour around submersible platform foundation in drill or explore process. Sediment scour of platform foundation could induce platform slide, even lose the stability, which threaten platform safety. Foundation scour is the most important issue of submersible platform safety operation.

Wang (1998) carried out scour experiment around submersible platform foundation in wave and current interaction. The results showed that there were scour area under platform foundation and scour holes in front and side of foundation look like U shape. Wave and current interaction increase scour probability, mainly because of the large-scale eddy erosion and current transportation. Zhong (2003) analyzed scour process and principle around platform foundation in Chengdao oilstate and researched scour origin and velocity of pile foundation, which provide reliable reasons for design and construction. Han (2006, 2007, 2009) researched the silty sand scour around artificial island and structure through series model theory and analyzed the sand scour variation under different combination of wave and current.

In order to investigate scour ability around submersible platform and take anti-scour method to protect the platform foundation, series model theory was adopted to research scour character around submersible platform. The experiment was carried out in wave tank of CNPC key laboratory of Offshore Engineering.
Use of Wireline Formation Tester Stress Measurements and Sonic Logs for Improved Geomechanical Model Construction of a Giant Depleted Gas Reservoir in Abu Dhabi Land: A Case Study
Authors: Cig Koksal , Osunluk Halil Ibrahim , Povstyanova Magdalena , Masoud Rashad , Ammari Khalid
Published: March 2015

Abu Dhabi land has a giant gas field consisted of layered carbonate reservoirs. The long term plan of the field has been to produce the reservoirs with the safest maximum depletion. A detailed geomechanical study was undertaken to identify changing field stresses and to understand the possible reservoir rock collapse mechanisms.

The foundation for any 3D geomechanical modeling is 1D Mechanical Earth Model that includes elastic and strength properties, overburden stress, pore pressure and magnitude and direction of horizontal stresses. The input data for 1D modeling is openhole logs (density and compressional and shear sonic logs). Image data, caliper logs, pore pressure and closure and breakdown pressure measurements are necessary to calibrate the models. To improve quality and reliability of the 1D MEMs, Abu Dhabi Company for Onshore Oil Operations (ADCO) requested lab measurements to calibrate elastic and strength rock properties and decided on pore pressure and stress measurements in one of the upcoming wells. Wireline Formation Tester (WFT) technique was selected to provide pore pressure, as well as closure pressure to calibrate magnitude of minimum horizontal stress directly and breakdown pressure to calibrate magnitude of maximum horizontal stress indirectly. Acquired compressional and shear sonic logs allowed building continues properties, pore pressure and stress profiles.

Introduction

3D geomechanical modeling was conducted for the interested reservoirs in the Bab field. The main objective of this study was to investigate possibility of formation rock collapse, particularly within severely depleted areas, and associated well collapse and completion integrity damage. This study also aimed at assessing potential geomechanics-related risks due to early depletion (cap rock integrity and fault sealing capacity).

Figure 1 shows the general workflow of this study. Firstly, 1D Mechanical Earth Models (MEMs) were constructed using available wireline logs. The measured data was used to calibrate the calculated elastic and strength rock properties, pore pressure and horizontal stress profiles. Drilling reports were analyzed to extract wellbore instability-related events to calibrate the 1D MEMs further. To better capture variation of elastic and strength properties across the reservoir, 1D MEMs were constructed for several wells. Then, a 3D MEM was built based on the static geological model and dynamic reservoir model. 1D MEMs were used to populate the mechanical properties for 3D modeling carried out for the duration of pre-production until present. The results were calibrated against the production data. The calibrated 3D model was then used to perform two-way coupled modeling for future rock behavior in the cap rock and reservoir depletion mechanism.
ComProMisE: an Innovative Method for Combining Proportion Cubes for Facies Modeling
Authors: Tawilé Eric , Ahn Sung-Bin , Schirmer Patrice
Published: March 2015

Compromise is a methodology that is based on an iterative solver that allows combining multiple proportion cubes given that a priori reference proportions are provided within a defined facies simulation perimeter. The novelty of the methodology is the possibility to choose the amount of imprint of a given trend while respecting quantitative proportion constraints.

It has been successfully tested on several operational studies and is now used in a routine basis whenever having multiple facies trends to manage. For each study, the proportion cubes were provided by different sources; the methodology is source independent as long as it is expressed as a proportion cube. Seismic, concept and well data are possible sources of proportion cubes.

It is tool-independent and is implemented today as workflows and scripts. It is also planned to be developed as an independent module on for increased user-friendliness.