bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deploying New Technology To Improve Canada's Underbalanced Operations
Authors: Pavel D.A. , Mitchell T.M. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
As global trendsetters in underbalanced operations, Canadian operators are taking a bold new approach to the drilling phase. Recently as a result of increased QHSE concerns around snubbing operations, operators are considering alternative methods to trip under live well conditions. This presents the opportunity to explore new alternatives in pressure control during underbalanced operations, as opposed to conventional methods such as snubbing and killing the well with an overbalanced fluid column. These methods createglaring problems such as rig non-productive time, environmental and safety hazards, and wellbore damage. One such alternative is the downhole isolation valve.
The downhole isolation valve is a casing deployed valve system that is set at a predetermined depth and used to shut-in the well to allow for deployment of the drill string and completion assemblies.
This paper will discuss the needs of operators and how they were met with the downhole isolation valve, the benefits realized by deploying this technology, and the results from wells where these tools were run.
An Innovative Geoscience and Reservoir Training Passport for New Recruited Engineers Worldwide as per Sustainable Development
Authors: Coste Jean-Francois Michel , Estival Jacques , Lecanu Hubert , Beauchamp Michel 
Published: February 2016

Abstract
The Oil industry has to face a significant aging of its E&P task force and its correlative retirements in a few years. In preparation for this crew change, a consistent hiring programme of hiring is being implemented within Total both at the Headquarters and in the affiliates worldwide. Giving these new engineers the required skills quickly poses a big challenge.
Once recruited, every new engineer in Geosciences and Reservoir disciplines is given a Training Passport. In other words, he will follow a personalised curriculum corresponding to about 6 months training distributed over a 2 to 4 year period.
This road book is designed to fill the gap between initial – on hiring - and expected skills.
For each discipline – i.e. Geophysics, Geology, Reservoir – the technical skills as well as the Personal and Management development objectives are exhaustively listed. An accurate training path comes from a skill list and the training proposal, both in-house and externally. For the Reservoir Engineering discipline, the list contains: HSE, Induction, G&G basics, Well Data acquisition and Interpretation, Well Performance, Reservoir geo-modelling and simulation, Uncertainties integration, Field Monitoring and Management, Economics, Project Management, etc…
During the Passport implementation, the new engineer is assigned to a Technical Department where he can apply what he has just learned through the specific training courses. The training effort represents on average up to 15% of the yearly working time. Launched in 2003, the Training Passport approach is being extended to all affiliates starting with Western Africa. The Young engineers Training Passport generates consistency in professional disciplines, and increases visibility and anticipation for all actors involved. It provides the young Headquarters engineers with required autonomy before being assigned in affiliates worldwide.
Because it is a skill driven and a long term process, the Training Passport represents a significant cultural change that efficiently allows us to meet the needs of the Company strategy.
The Impact of Water-Injection-Induced Fractures on Reservoir Flow Dynamics: First Applications of a New Simulation Strategy
Authors: Hustedt Bernhard , Qiu Yuan , Zwarts Dirk , van Schijndel Luc , van den Hoek Paul Jacob 
Published: February 2016

Abstract
We present benchmark simulations and a real-field application of a new coupled fracture growth / fluid flow simulator.
The coupled reservoir simulations compare well for various synthetic test scenarios. The application to a real five-spot injection trial demonstrates the importance of the new modelling tool for optimal reservoir management.

Introduction
In many fields secondary recovery is playing an increasingly important role to maintain oil production. The recovery of the remaining oil is a major task that, due to the complexity of many reservoir formations, requires an extensive knowledge of the subsurface. Probably the cheapest and most often applied technique to sweep a reservoir is a waterflooding project.
Injection of water in the reservoir formation is often accompanied by, unnoticed, induced fracture propagation. Dynamically growing or shrinking fractures have a huge impact on the reservoir management strategy and, if not handled properly, may risk the success of the whole water injection process. Hence, dynamic fracture propagation should be an integral part of a standard reservoir simulation study. Then, an optimal waterflood implementation may be achieved which guarantees an overall increase of recoverable oil.
Next to waterflooding are numerous other applications where induced fracture mechanics play a significant role in defining the reservoir behavior. Typical examples are water injections for reservoir pressure maintenance of e.g., green or brown fields, and safe disposal of produced water by re-injection.
In the past, varying approaches have been presented to study fluid flow and fracture growth during reservoir simulations. Implicit and explicit coupling techniques have been developed and tested for varying theoretical and practical scenarios. The main differences are to which extent the interaction and uncertainties of a coupled fluid flow-rock mechanics model are incorporated in the simulation tool. To our knowledge, these tools are not widely used in the industry on a standard basis, since the models need to be purposed-built and, therefore, require an extensive effort to be put into place.
Exploring the "Empty Quarter" - Early Experience and Lessons of a New Upstream Venture in Saudi Arabia
Authors: Allman-Ward P. , Voggenreiter W. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Under the terms of the Upstream Project Agreement ratified in November 2003,the South Rub Al-Khali Company Limited (SRAK) has entered into an agreement with the Kingdom of Saudi Arabia for the exploration, appraisal, development and production of non-associated gas, condensate and natural gas liquids in Contract Areas 1 (Blocks 82–85) and 2 (Blocks 5–9) in the South Rub; al KhaliBasin of Saudi Arabia. SRAK is an Incorporated Joint Venture between Shell(40%), Saudi Aramco (30%) and Total (30%), with Shell providing the technical lead.
Exploration activities under the terms of the Upstream Project Agreement are governed by a first five year exploration term and two subsequent five year exploration periods undertaken at the option of SRAK. Work commitments for the first exploration term encompasses a major seismic acquisition programme of16,000 km of 2D data and the drilling of seven exploration wells. The exploration acreage covers an area of approximately 210,000 km2, equivalent to10% of Saudi Arabia's land area. SRAK's exploration efforts will be focused on the Palaeozoic reservoirs. In contrast to the hydrocarbon-rich tracts within the Saudi Aramco Reserved Area some distance to the north, the remote SouthRub, al Khali Basin is only lightly explored, and the presence of a working(Palaeozoic) hydrocarbon system has yet to be demonstrated.
Eighteen months into the first exploration term, this paper focuses on the venture related as well as technical challenges that are being faced and how they are being addressed.
Physics-Based Well Design - Beyond the Learning Curve
Authors: Kline William E. , Chandler Karen , Keller Stuart Ronald , Ottesen Steinar , Gupta Vishwas , Tenny Matthew 
Published: February 2016

Abstract
In a drilling program, the design of wells has historically been an incremental process in which compiled experience from previously drilled wells is the principal driver for realizing drilling design. The efficiency of drilling in a field, and as a result, the cost, typically improves significantly initially, before reaching a point at which little improvement is achieved. The progression from the initial well to the final wells of a mature drilling program is often referred to as the "drilling learning curve." Rather than focus on getting the design right after several wells, it is possible to outperform the learning curve by developing and applying fundamental physics-based models and computational optimization engines up front to quantitatively analyze well design options. These proprietary tools have been applied extensively in field development planning, as well as in real-time, to ensure optimal drilling performance. This paper describes ExxonMobil's approach to physics-based modeling, advanced mathematical optimization, and real-time updating to achieve drilling performance that both accelerates and undercuts the historical learning curve. Specific business examples illustrating successful applications of this approach are presented.

Introduction
Optimal well design requires attention to both fundamental engineering principles and site-specific learnings. The drilling learning curve, which identifies adjustments to initial design parameters to improve overall well design, can frequently cut 50% or more from well costs over the course of a continuous program. While a variety of learning-based well design techniques have served the industry well, the biggest prize is achieved by utilizing physics and mathematics to shift the optimization process from the learning curve to the initial well design – getting it right the first time.
ExxonMobil's approach to going beyond the learning curve is based on routine application of proprietary technology that couples fundamental physics-based models with statistical analyses. The models enable the accurate prediction of expected drilling performance over a wide range of operational conditions. By accounting for downhole parameter uncertainty, engineers effectively optimize this performance over all expected scenarios.
Applications of Petrophysical Scale Reconciliation to Saudi Arabian Reservoirs
Authors: Worthington Paul Francis , Al-Ali Hussein Ali 
Published: February 2016

Abstract
Core data from three fields have been stress-corrected and upscaled so that they become notionally reconciled with wireline well logs along wellbore axes. The upscaling process draws upon logging tool response functions in a way that optimizes the correspondence between the smoothed core porosity data and density or sonic logs. It is demonstrated that there are significant differences between core-derived porosities at the core and log scales. These differences are tool-specific, and they transmit through to the log-derived porosity. Once a scale-reconciled log-derived porosity has been validated, it can be input to a core-derived porosity-permeability algorithm. Where this transform is based on compatible, upscaled core data, the results are significantly better than those from the conventional approach that is tied back to the core-plug scale. These observations have formed the basis for improved workflows for the petrophysical evaluation of porosity and the subsequent estimation of intergranular permeability. The approach can be readily extended to the evaluation of water saturation where low-invasion coring has taken place.

Introduction
Core-to-log integration is a fundamental petrophysical component of integrated reservoir studies, because it provides the groundtruthing for well-log analysis. Historically, log responses have been tied back to core data with little attempt being made to take account of the different scales of measurement. More recently, however, there has been a renewed interest in redressing this situation, even though it is recognized that a full reconciliation of core and log data might not be possible, because of the different volumes of rock sensed by these two types of measurement. Success at this stage delivers further benefits when porosity is used as a predictor for the evaluation of other parameters such as permeability.
In this paper, petrophysical scale reconciliation is examined from two specific standpoints. The first is to process conventional core porosity data so that they provide the best possible groundtruthing for the evaluation of porosity from density and sonic logs.
Optimizing Well Test Sequence and Duration Using Real-Time Pressure Transient Analysis (RT-PTA)
Authors: Adeyemi Olutope S. , Cribbs Myrt Eugene , Lindo Octavio 
Published: February 2016

Abstract
Both conventional and non-conventional well testing and sampling operations require some form of design a priori. Due to the uncertainties in input parameters during the test design stage, test sequence and duration are mostly adhered to especially when memory gauges are being used. These uncertainties are more pronounced during exploratory or appraisal testing; hence, being able to make adjustments throughout the testing operation can result in significant value creation, particularly when operating in a high cost deep water environment.
This paper describes how real time pressure transient analysis (RT-PTA) may be used to optimize test sequence and duration in exploratory well testing and sampling. Two case histories are presented that show the impact and value added by combining real time data acquisition, analysis and decision making in the test procedure. Value is achieved by making informed decisions to redesign the test sequence to better meet test objectives, improved stakeholder communication concerning the reasons for these changes and improvements in contingency planning. It is the authors' hope that these examples will be useful to our peers when engaging in Value of Information (VOI) discussions.
Several modes of deployment currently exist for downhole data acquisition and transmission to the surface in real time. Case histories showing results from the application of two of these deployment techniques are presented. While no effort has been made to demonstrate the superiority of one method over another, emphasis has been placed on the impact of enabling real time monitoring and analysis of data acquired during well testing operations. The two methods presented, tubing encapsulated cable (TEC) and an acoustic telemetry system (ATS), were deemed most appropriate for each specific application.
The suitability of this approach for conventional and non-conventional well testing and sampling, the ability to adapt this technique to different types of tests and of being able to revise test sequence in real time to more efficiently accomplish a given set of goals makes real-time pressure transient analysis (RT-PTA) very attractive.
The Potential of Multiple Fractured Horizontal Wells in Siberian Oil Fields
Authors: Butter M.K. , East L.E. , Kuvshinov K. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Many of the Western Siberia oil fields are being developed/exploited with hydraulically fractured S-shaped wells (vertical through the pay section).Horizontal wells are also used; however, in many of the fields these wells are out performed by the vertical fractured wells. The reasons for this appear to be poor vertical permeability and sub-optimal drilling and completions practices.
To better quantify the potential of an undeveloped area of a western Siberian oil field, five different well types were evaluated: Vertical, Vertical-Fractured, Slanted (80 deg crossing multiple layers), Horizontal (with a single layer), and Multiple-Fractured Horizontal wells. These well completion types were evaluated using a reservoir simulation model of a sector of the field. The results of this analysis demonstrated that the multiple fracture horizontal well completions outperform the other well types and that they can have a substantial positive impact on the economics of the field development.
With traditional fracturing and completion techniques, where packers or bridge plugs are used to provide zonal isolation, fracturing horizontal wells is a complex operation with increased risk and not always economical. New pin-point fracturing techniques can eliminate many of these problems and reduce risk. Recent developments in these technologies make it possible to perform the same type of aggressive frac jobs as currently performed in vertical wells, with large proppant volumes and large proppant sizes (12/18), at multiple selected locations along a lateral wellbore.
To realize the full potential of this type of completion plan, traditional thinking, regulatory barriers, and equipment limitations need to be overcome. This process has started, and some operators are currently planning trial multiple fractured horizontal wells to demonstrate the potential.
This paper illustrates the potential demonstrated by the development study and recent technology developments that will allow the placement of multiple fracs in horizontal wellbores and the practical aspects that need to be addressed for operators to fully capture the potential.
A number of operators have firm plans to perform such fracs in horizontal wells. If performed in time, approval will be sought to present case histories in this paper.
Production-Induced Deformations Outside the Reservoir and Their Impact on 4D Seisimic
Authors: Kristiansen Tron Golder , Barkved Olav Inge , Buer Kjell , Bakke Roger 
Published: February 2016

Abstract
This paper is reviewing 4D seismic data from the Valhall field located in the chalk province on the Norwegian continental shelf. The field is monitored with 4D seismic and is the first field in the world to be monitored with permanent installed cables at the seafloor. This concept, including 120 km cables trenched into the seafloor above the field, is providing seismic on demand for reservoir management purposes and is called Life of Field Seismic. This paper will focus on the seismic observations of production induced deformations outside the reservoir at Valhall and will review the theory behind the deformations, how they impact the seismic velocities and the use of 4D seismic for reservoir monitoring. The paper will present integration of relevant theories, numerical modelling and results from laboratory experiments.
The work presented should have applications to other fields where even limited reservoir compaction will take place. How significant the reservoir compaction will be is dependent on the structural geometry, rock properties of the surrounding rock, reservoir thickness, the compressibility of the reservoir, the pore pressure depletion and if any weakening of the rock takes place during secondary or tertiary recovery processes. The methods presented in the paper can also be used to improve the uniqueness of the static geologic model, the dynamic flow model and the geomechanical model and, hence, result in a more unique history match of the reservoir as well as improved future prediction.
The main technical contributions from this paper are a detailed review of theory, laboratory and field data of relevance from a well instrumented field under seismic surveillance. The paper will also outline how integration of geophysics, geology, geomechanics and reservoir engineering can produce better reservoir performance prediction based on new workflows. The paper will also show how a problem of production induced deformations outside a reservoir, with corresponding velocity changes, may be used as an advantage in reservoir performance prediction in the future.
High-Resolution Static/Dynamic Modelling and 3-Phase Streamline Simulation in Complex Fluviatile Reservoirs
Authors: Olewczynska Marzena M. , Grotsch Jurgen , Al Jundi Jamal , Rao Shankar 
Published: February 2016

Summary
This paper presents the application of high-resolution static and dynamic modelling in complex faulted fluviatile sandstone reservoirs. It is based on results of an integrated study of one of AFPC's fields in the Euphrates Graben, Syria, with the Cretaceous Lower Rutbah and Triassic Mulussa F1 & F2 forming the three main reservoir units. It describes the modelling challenges and the advantages of high-resolution models in reproducing the dynamic reservoir processes as observed from well data. It also shows how a dynamic process-based modelling workflow resulted in history match improvements and higher reliability of predictions. Subsequent field implementation of the project recommendations provided the ultimate validation of the modelling approach and demonstrated the predictive value of the models.
The paper also highlights the added value of 3-phase streamline simulation in full field history matching and improving the understanding of flow paths in the reservoir as a result of the interplay of fluvial channel sands and numerous fault juxtapositions. It compares streamline simulation with the traditional finite difference simulation results and describes the strengths and weaknesses of streamline simulation applied during history matching.

The Reservoirs
The investigated field has three main reservoir formations, which are the Lower Rutbah (RUL), Mulussa F1 (MUF1) and Mulussa F2 (MUF2), shown in a schematic cross section in Figure 1.
The Mulussa F sequence (MUF) is dominated by fluvial sandstone bodies alternating with flood plain fines and soil horizons. The reservoir quality of sands is good (average net porosity of some 16%, permeabilities ranging from 30 to 1000 mD, average oil saturation of 83%). The Triassic Mulussa is separated from the overlying Cretaceous Lower Rutbah formation by the regional BKL unconformity, which resulted in partial erosion of the formation within the field area, in particular in the western part. Hence the MUF1 varies greatly in thickness over the field, whereas the MUF2 has a layer-cake architecture (at the level of major stratigraphic units). Another key difference between the MUF1 and the MUF2 formations is the N/G ratio, which is high in the MUF2 (50–70%) and low in the MUF1, where it only attains 30%.