bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design, Implementation and Performance of a Down-Dip WAG Pilot
Authors: Choudhary Manoj Kumar , Parekh Bimal , Dezabala Edward , Solis Hector Arturo , Pujiyono Pujiyono , Zambrano De Narvaez Judith Zambrano 
Published: May 2016

Abstract
Water-alternating-gas (WAG) injection is an enhanced oil recovery (EOR) method aimed at increasing sweep efficiency by contacting zones that are not adequately swept by water injection and by increasing microscopic displacement efficiency as gravity-aided WAG injection often gives lower remaining oil saturation. WAG performance also depends on whether it is updip or down-dip injection. Most WAG case studies available in the literature are up-dip WAG injection and most fields with WAG are in North America. This paper will present a case study of down-dip WAG in a field offshore West Africa. Field E is located offshore West Africa. Production from the gently dipping reservoir started in December, 2006 with peripheral water flooding as a primary recovery method. A WAG injection pilot was implemented in a down-dip injector in June, 2009. The main motivation for WAG injection was to reduce gas flaring with a secondary objective of improved oil recovery. Design, implementation and surveillance of the WAG pilot required a multi-disciplinary approach. Coordination between the subsurface and the operations teams was key to ensure timely implementation of the WAG pilot as per the design including subsequent data gathering.
For WAG pilot design, a full-field simulation model was built and history matched. Sensitivity runs were made to optimize fluid injection rates and WAG cycle size to reduce flared gas volumes without having a negative impact on recovery. Conversion of a down-dip water injector to WAG required minimal facilities modifications. A comprehensive reservoir surveillance plan was developed to monitor WAG performance. Surveillance results to date indicate down-dip WAG is having a positive impact. Based on encouraging results and on updated simulation modeling, the WAG pilot has been expanded to another injector. The paper will discuss details of down-dip WAG pilot program design, implementation, surveillance and performance.

Introduction
Field E was discovered in May 2001. The exploration well encountered oil-bearing turbidite sands of Campanian (Upper Cretaceous) age. To date several exploration and appraisal wells have been drilled in and around the area, identifying multiple, normally-pressured hydrocarbon accumulations.
Field E is located on the present day continental shelf in ~65 m of water at an average reservoir depth of 1,000 m. Seismic mapping (Figure 1) identifies two meandering canyons. The North-East canyon (E canyon) is where Field E is located. It is a gently dipping reservoir with dip angle varying from 5º to 10º. A cross-section through Field E is shown in Figure 2. There are several mapped faults. Based on the field performance, these faults are acting as baffles to fluid flow. Trapping in Field E is primarily stratigraphic with some local structural fault intersection closures.
Comparison of Fluid Prediction Success between AVO and Bright Spot Techniques in the Marco Polo Field, the Gulf of Mexico.
Authors: Suwannasri Krongrath , Tatham Robert H. , Spikes Kyle 
Published: May 2016

Abstract
Bright spot amplitude anomalies in seismic data are common indicators of natural gas; however, an interpretation based purely on these amplitude anomalies often yields a false indication of gas-saturated sands. A data set from the Marco Polo field, the Gulf of Mexico, demonstrates this problem. A discovery well was drilled into a sequence of bright spot anomalies that were indeed gas-saturated sands. This suggested that other bright spots in the seismic section also corresponded to gas sands and that non-bright spots were to brine-saturated sands. Nine development wells were later drilled into those bright spots, but not all of them were gas sands and not all of non-bright spots were brine-saturated sands. This study utilized Gassmann fluid substitution and three seismic amplitude versus offset (AVO) techniques (intercept and gradient, elastic impedance, and Lambda-Mu-Rho) as a comparison to purely using bright spots technique for fluid-type prediction at the location around the discovery well. This study used borehole information only from the discovery well in the purpose of AVO calibration. Forward models for the three AVO techniques were created from the well-log information in order to predict differences in the modeled attributes between gas- and brine-saturated scenarios. Pre-stack seismic data were inverted for intercept and gradient attributes, elastic impedance (EI) volumes, and Lambda-Mu-Rho (LMR) volumes. These volumes were compared to the forward models to predict gas- and brine-saturated locations. The prediction results were evaluated with information from the nine development wells. The intercept and gradient, elastic impedance, and LMR techniques yielded correct predictions of 52%, 61%, and 70%, respectively, of the observed sands. The traditional bright spot method yielded only 45% of correct fluid prediction. In conclusion, the pre-stack AVO techniques provided a better fluid prediction than relying solely on the post-stack bright spots alone. Furthermore, the prediction results improved as the computational intensity of the inversion increased from the intercept and gradient, to the elastic impedance, and to the LMR technique.

Introduction

Bright spot and its pitfall.
The use of bright spot seismic amplitude anomalies to predict the location of petroleum resources has increased over the past four decades; however, this technique can be unreliable and inaccurate. Bright spot amplitude anomalies are purely an elastic effect. Only the right combination of petroleum fluid content and rock physics properties (such as porosity and lithology) can result in bright spot amplitude response. Thus, the bright spots do not always represent the presence of petroleum fluid, and non-bright spots do not always mean the absence of petroleum fluid (Young, 2006).
A Pragmatic Approach to Enhanced Performance of Slim Mono-bore Wells
Authors: Lam Fei Shiong 
Published: May 2016

Abstract
Continuous development and refinement of e-line based well intervention methods help push the performance envelope and expand the possibilities for optimizing reservoir drainage. The light and agile approach increasingly adds a new dimension to reservoir management as well intervention becomes viable. In general the resources required to perform production enhancing well intervention have been reduced, which again has a direct impact on the potential revenue.
This is exemplified by a Malaysian well where build-up of scale almost ceased production. Opening the wellbore by milling out part of the accumulated scale immediately increased the production by 50%, 14 hours after the intervention operation was initiated.
This, and similar cases are addressed by the paper with a particular emphasis on the practical aspects of lightweight well intervention utilizing e-line conveyed tools in relation to slim and/or mono-bore wells as commonly found in Asia.
One other case is the successful recompletion of a mono-bore water injector done purely on e-line by way of setting a plug to isolate an existing perforation interval and re-perforate higher up in the well. Significant increase in reservoir ultimate recovery as well as oil gain over the following years of production from the H sand was realized.
Another example is the recovery of 350 liters of muddy sand from an onshore gas well thru a 3-1/2" tubing in Indonesia using e-line downhole tools.

Technology Description

Wireline Tractor
Wireline tractor technology was first introduced in 1994 (Hallundbaek, J., 1994), and the technology was primarily used for conveyance of diagnostic logging tools. However, as it achieved a reliable track record, it began to form part of many oil companies' standard solutions.
The wireline tractor (Figure 1) functions with an electric/hydraulic power relationship. The control panels, communications and internal power source are electric, while the remaining parts and functions are hydraulic. When activated, the wheels are hydraulically deployed out of the tool body and automatically start to rotate. Each wheel contains its own independent hydraulic motor, which facilitates the forward motion in the well. The tool centralizes itself in the well bore once contact with casing has been established and the cumulative traction force between the wheels and the casing wall then deploys the intervention tools into the well bore, taking the string beyond its original hang up point. Horizontally, the wireline tractor can pull a wireline beyond 9,800ft into the well bore and more than 25,000ft into a highly deviated well in addition to pushing other down hole tools (Hallundbaek, J., 1994). When target depth has been reached, the tool is powered down. The passive and immediate fail-safe feature ensures that the wheels are retracted automatically when it is powered down or disconnected.
Fiber Optic Technology for Reservoir Surveillance
Authors: Koelman Johannes V. Vianney , Lopez Jorge L. , Potters Hans 
Published: May 2016

Abstract
Fiber-optic sensing technology for in-well applications has traditionally focused on temperature profiling. This has limited the application of fiber-optic reservoir surveillance to recovery processes with a pronounced thermal signature. Currently, novel fiber-optic technologies entering the market promise a much wider range of subsurface measurements. This opens new avenues in well and reservoir management and highlights the opportunity for fiber-optics to become a pervasive oilfield technology. In this paper we discuss field trials that combine Distributed Temperature Sensing (DTS), Distributed Strain Sensing (DSS) and Distributed Acoustic Sensing (DAS). These trials demonstrate the potential of fiber-optic sensing technology for well integrity monitoring, gas lift optimization, in-flow profiling and downhole seismic acquisition.
Esential to realizing this potential is the development of cost-effective, easy-to-deploy fiber-optic cables optimized for these various fiber-optic measurements. We also highlight the business integration challenge of handling, storing, and interpreting data volumes that in some applications reaches levels of 1 TB/well/day. We conclude that while significant technology challenges remain, with a broad cross section of oilfield technology providers working on derisking fiber-optic sensing technologies, the industry is on the verge of a step change in well and reservoir monitoring capability.

Introduction
Its passive nature and inherent long-term reliability, combined with the ability to string together numerous individual sensing elements in a single fiber, makes fiber-optic technology ideally suited for distributed sensing in harsh and remote environments. Despite this compelling proposition, for many years this technology was synonymous with temperature sensing and thereby limited to the monitoring of well operations and recovery processes with a pronounced thermal signature. In recent years, this situation has started to change rapidly. A variety of fiber-optic sensors developed in the aerospace and defense industries are finding their way into the oil and gas industry. As multiple fibers, each providing a specific distributed measurement, can be bundled in a single downhole-deployable cable, the industry is facing a unique opportunity for robust well and reservoir surveillance based on an abundance of measurements continuous in time during the well's productive life and continuous along its well path.
Enhancing Recovery in High Salinity Oil Reservoirs through Optimized Polymer Flood
Authors: Algharaib Meshal Kh , Alajmi Abdullah Fahad Faleh , Gharbi Ridha 
Published: May 2016

Abstract
The applications of Enhanced Oil Recovery (EOR) techniques are encouraged by the growing demand for oil. Optimizing oil production from current resources is becoming the main strategy for many oil producing companies around the world. Among EOR processes, polymer flooding is an attractive option in many reservoirs. The objective of polymer flooding is to control water mobility inside the reservoir to favor higher oil recovery. Several design parameters are critical for the success of polymer flooding applications. The salinity of formation water is one of the challenges which impose a limitation on polymer flood applicability. In Kuwait, most of oil reservoirs are high water salinity reservoirs. Therefore, improving the performance of polymer floods under high water salinity conditions may unlock these resources which can have enormous positive effects on oil reserves. One way for this improvement is to condition these reservoirs by injecting a slug of water (preflush), ahead of polymer, with specific characteristics. In this work, lab experiments were conducted in which the effects of several design parameters of polymer flooding are investigated under high water salinity conditions. Design parameters include preflush salinity, preflush viscosity and preflush slug size. The results suggest these parameters correlate differently with oil recovery factor.

Introduction
With the current growing demand for oil led by major energy consuming countries such as China and India, securing new oil resources is a critical challenge for the oil industry. Adding new oil reserves can be achieved by finding new discoveries or by optimizing oil production from current resources. The cost associated with the first option is significant since the new resources are expected to occur in challenging environments such as deep formations or deep water. Therefore, the need to optimize oil production from current resources through Enhanced Oil Recovery (EOR) techniques is a main strategy for many oil producers. EOR processes are generally classified as thermal, miscible, or chemical processes. Reservoir's rock and fluid properties and economics dictate the choice of which EOR process to follow. Thermal methods are mainly used in heavy oil reservoirs; whereas miscible processes are suitable for lower viscosity oils. Chemical EOR processes are used to reduce reservoir forces responsible for oil entrapment. There are different versions of chemical processes depending on the type of fluid used such as: polymer, alkaline, and surfactant.
Rock Type Classification and Saturation Modeling in a Heterogeneous Low-Permeability Reservoir from Offshore India
Authors: Agarwal Gunja , Sagar Rajiv , Behera Bijay 
Published: May 2016

Abstract
In any reservoir modeling exercise, accurate estimation of initial water saturation is crucial to determine the in-place hydrocarbon volumes. The water saturation in a reservoir is a function of the reservoir rock quality and the capillary forces present.
Pore throat size distribution and rock quality strongly influence the amount of capillary-bounded water and mobile water in the reservoir rock. A good understanding and proper classification of rock types based on reservoir quality is essential for reservoir property population. Also, in absence of the core data, the practice of using single-well models and well logs to identify capillary pressure curves and hence water saturation distribution is not ideal for a vast heterogeneous reservoir with many wells.
A case study is presented in which extensive core data, in particular RCA and SCAL results, are analyzed. These results are integrated with petrophysical interpretation to identify different classes of sand units based on the reservoir rock quality and amount of clay present. It is uniquely noted in this work that volume of clay, Vclay, was a better basis for rock classification in this reservoir.
A numerical method is used to unify and integrate SCAL data acquired over a 1000-m section of the reservoir in more than 10 drilled wells. Parameterized equations are derived to populate initial water saturation in the static or dynamic model. The water saturations obtained from these parametric equations are subsequently validated with the well log saturations and vice versa. These results are further validated by history matching the drillstem test result, showing excellent results.
Indonesia "Tunu 18 days" Project Case History: Innovations and New Technologies Bringing the Well Construction Performance to Unthinkable Levels
Authors: Oumer Samir , Widiwibowo Fajarianto , Yunus Fata , Choux Jean-Claude 
Published: May 2016

Abstract
Tunu is a giant gas field discovered in 1977 and located in the Indonesian Mahakam delta, East Kalimantan. To support the field development maintaining a high gas production level, more than 750 wells have been drilled and completed. Late 2010, Tunu field cumulative production was over 7.5 Tcf gas.
Five rigs are continuously drilling in the swamp area to deliver around 100 wells per year highlighting the stakes associated to the well construction optimization. Since the 80's and the early beginning of the drilling operations on Tunu, a tremendous work has been done to 1) reduce the overall well construction duration, 2) reduce the well equipment costs without jeopardizing the operations safety and the wells productivity. The first important leverage was the implementation of innovative well architectures in order to construct "fit for purpose" wells strictly answering to the subsurface formation characteristics avoiding any over design. The evolution of the technology has been fully utilized and wisely implemented in order to improve the performance of our drilling and completion operations. A huge effort has been delivered to minimize the costs associated to the equipment design and material selection. Finally, a shared performance culture has been successfully implemented on our operations to systematically challenge ourselves outside of our comfort zone: the "Industrialization" of the well construction process is now developed.
The Tunu wells targeting the "main zone" reservoirs have seen their average duration reduced by 70%!!! From a well duration of 55 days in the early 80's, the drilling and completion teams managed to reduce it down to 17 days in 2011.
This performance level has been reached over 30 years of thorough improvement process follow-up. A joint effort of all involved entities as geosciences, marine, logistics, planning, service companies and well teams made this achievement possible.
In 2011, two innovative well architectures have been implemented on Tunu and field trials are planned for two new technologies. The continuous improvement process is not closed yet: "Tunu 15 days" on its way to become a reality?
The North Malay Basin: Analog for the Reservoir Distribution of the Triassic Rift Basins, Northeastern Thailand
Authors: Pongpisuttinan Teerapong , Anis Ahmad , Ponthanom Piyanuch 
Published: May 2016

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

Abstract
The North Malay Basin is an intra-cratonic basin formed by rifting in early Tertiary time. North-South (N-S) and Northwest-Southeast (NW-SE) oriented normal faults form a series of asymmetric half grabens. Some of these have shown the best imaged seismically. Combined with a number of wells that penetrated the synrift section in this and adjacent half-grabens, leads us to a clear picture of the overall geometry and reservoir distribution of the basins. In attempt to understand more about the nature and type of reservoirs encountered in the North Malay Basin, Na Phor Song, the Triassic Rift Basin located in northeastern part of Thailand was selected to conduct geological field survey. The outcrop exposures of this basin and subsurface data from the North Malay Basin were studied and compared, resulting in the definition of 8 synrift sedimentary facies: Alluvial Facies, Fluvial Facies, Proximal Delta Facies, Shoreface Facies, Lacustrine Swamp Facies, Distal Delta Facies, Deep Lacustrine Facies and Fan Delta Facies.
The same facies observed in the outcrops can be interpreted from well control and seismic sequence analysis in the half graben, North Malay Basin. The areal distribution of the seismic facies can provide important insights to understanding the overall geometry of the Triassic Rift Basins. The facies successions observed in outcrop in the Triassic Rift Basins provides the means to better understand and define synrift reservoir fairways in the North Maly Basin. The seismic and well facies evaluation conducted in the exploration program for the North Malay Basin can provide insights to better understanding the reservoir distribution in the Triassic Rift Basins. Together, they can provide the means to improve the prediction of reservoir and source-prone facies other rift basins in the Gulf of Thailand.
Electromagnetic Casing Inspection Tool for Corrosion Evaluation
Authors: Brill Thilo Michael , Demichel Cindy , Nichols Edward Andrew , Zapata Bermudez Fernando 
Published: May 2016

Abstract
Pipe corrosion is a natural phenomenon in the harsh environment of oil and gas production wells, costing billions of dollars each year. Monitoring such corrosion allows for timely mitigation to prevent leaks, environmental damage, or catastrophic failures.
Corrosion of pipes is inferred from measurement of internal diameter and wall thickness. Mechanical finger calipers provide a high-resolution image of the internal pipe surface. Ultrasonic tools measure both the internal diameter and thickness of a single pipe, providing the pipe is filled with a fluid. Production tubing is a barrier to caliper, ultrasonic, and flux-leakage electromagnetic tools, preventing the assessment of outer casings. Remote-Field Eddy-Current (RFEC) tools respond to the total metal thickness of all the combined casings. The measurement is valid in single and multiple casing strings and is largely insensitive to the kind of material filling the pipe.
This paper presents a new slim electromagnetic (EM) imaging tool enabling casing assessment without removing the production tubing. The tool excites eddy-currents in the tubulars using a powerful low-frequency solenoidal transmitter. Distribution and strength of the eddy-currents depend on the geometric properties of the casings, their EM properties, and the presence of defects. The tool operates in the RFEC regime using large transmitter-receiver spacings, in which the measurements directly determine the total metal thickness. Mandrel-mounted coils provide the average total metal thickness, and eighteen small pad sensors around the tool provide an image of local pipe wall metal loss.
The combination of low- and high-frequency images, together with the average total metal thickness, provides a quantitative, high-resolution assessment of pipe condition. Log examples show detection of casing joints, additional casings strings, and presence of corrosion damage in the low- and high-frequency images.

Introduction
Corrosion is a relentless process with electrochemical, chemical or mechanical origins that is difficult to slow down: it is a 'silent killer' (Acuña 2010). In the oil and gas industry corrosion monitoring is used to assess the well condition as a basis for planning intervention and mitigation strategies. Among all the high-technology systems and equipment that are installed in oil and gas production wells, the corrosion of well casings causes the most problems. Apparently stable casing can suddenly develop a leak that may be the first evidence of a severely corroded section that left untreated may force abandonment of the well in the near future.