Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Gupta, M K (Oil and Natural Gas Corporation Ltd) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd) | Singh, V K (Oil and Natural Gas Corporation Ltd) | Pawar, A S (Oil and Natural Gas Corporation Ltd) | Deuri, BUDHIN (Oil and Natural Gas Corporation Ltd)
In an offshore field, mitigation of H2S from natural gas itself is a big challenge. A situation where high H2S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H2S from processed gas and oil.
In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H2S. Sour oil from the separator which contains around 2000 ppm of dissolved H2S is processed in a stripper column for mitigation of H2S dissolved in the oil. Sweet gas liberated from 1st two column of adsorber bed is used as stripping gas for oil sweetening. H2S liberated from stripper column is routed to the 3rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H2S level without the need of any rotating equipment's and must be a suitable for remote location.
A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.
Offshore wells drilled in the central and northern North Sea have historically suffered from borehole-instability problems when intersecting the Upper/Lower Lark and Horda Shale formations using either water-based mud (WBM) or oil-based mud (OBM). A wellbore-stability investigation was performed that focused primarily on improving shale/fluid compatibility. It was augmented by a look-back analysis of historical drilling operations to help identify practical solutions to the borehole-instability problems.
An experimental rock-mechanics and shale/fluid-compatibility investigation was performed featuring X-ray-diffraction (XRD) and cation-exchange-capacity (CEC) characterizations, shale accretion, cuttings dispersion, mud-pressure transmission, and a new type of borehole-collapse test for 10 different mud systems [WBM, OBM, and high-performance WBM (HP-WBM)]. The results of this investigation were then combined with the results of a well look-back study. The integrated study clearly identified the root cause(s) of historical well problems and highlighted practical solutions that were subsequently implemented in the field.
The borehole-instability problems in the Lark and Horda Shales have a characteristic time dependency, with wellbore cavings occurring after 3 to 5 days of openhole time. The problems were not related to mud-weight selection but were instead caused by mud-pressure invasion into the shales, which destabilizes them over time. An experimental testing program revealed that this effect occurs in both WBM and OBM to an equal extent, which explains why nonoptimal field performance has historically been obtained with both types of mud systems. New HP-WBM formulations were identified that improve upon the mud-pressure invasion and borehole-collapse behavior of conventional OBM and WBM systems, yielding extended openhole time that allows the hole sections in the Lark and Horda Shales to be drilled, cased, and cemented without triggering large-scale instability. Look-back analysis also indicated that secondary causes of wellbore instability, such as barite sag, backreaming, and associated drillstring vibrations, should be minimized for optimal drilling performance. A new HP-WBM system, together with improved operational guidelines, was successfully implemented in the field, and the results are reported here.
Hertel, Stefan A. (Shell International Exploration and Production Inc.) | Rydzy, Marisa (Shell International Exploration and Production Inc.) | Anger, Benjamin (Shell International Exploration and Production Inc.) | Berg, Steffen (Shell Global Solutions International B.V.) | Appel, Matthias (Shell International Exploration and Production Inc.) | de Jong, Hilko (Shell International Exploration and Production Inc.)
Digital rock technologies were developed to augment traditional core analysis and led to a much improved understanding of the microstructure of many rock core types. However, to produce an upscaled description of the reservoir, one must consolidate the measurements in scale over six orders of magnitude. Here, we show that a whole-core CT scan may serve as the natural link between the length scales of digital rocks and modern logging tools. While the CT scan contains a fingerprint of the structure of the reservoir, the digital rock models show the microscopic composition of each CT-scan voxel. For upscaling purposes, we established a quadratic correlation between the gray values in a CT scan and the porosities measured on core plugs. This correlation allowed us to generate a synthetic porosity log of millimeter resolution. After that, the length scale was increased using moving averages in the vertical direction. We investigated a thin-bed reservoir with layers of halite-filled sandstone alternating with layers free of halite at variable layer thicknesses. In this reservoir, the resulting synthetic porosity log compared well with the NMR log porosity within the uncertainty band over a total depth interval of 53.6 meters. We propose that field decisions could be accelerated if the quadratic correlation parameters can be generalized for these types of sediment. In this case, one may generate synthetic porosity logs as soon as the CT scan is available, which is typically the first step in standard core analysis.
Pulse testing, introduced in the 1960's, is a useful analytical technique to detect communication between wells and estimate interconnected reservoir properties. Despite its potential, it is rarely included in data acquisition programs. This is probably because engineers prefer to use interference testing, which can be easily detected and interpreted by reservoir simulation. Regretfully, the latter cannot analyse pulses which are so subtle that they are hidden within the tidal effects of pressure measurement.
In pulse testing, interconnected permeability is calculated from the time the pulse takes to travel from the producer to the observation well. In this paper, new formulations are presented for both linear and radial flow regimes. These are straightforward, making their application easy. Furthermore, they can detect whether pressure is propagated along channels or more extensive areal systems. The magnitude of the pulse can also provide invaluable reservoir characterisation. For a relatively homogenous system, this amplitude is easily calculated using either radial or linear coordinates. For more complex geometries, such as communication between different sands, detailed studies are required to quantify where and how the connectivity occurs between the producer and the observation well.
Often the pulse is significantly less than 0.1 psi which makes detection difficult, because of tidal effects, and analysis hard to interpret by finite difference simulation. Searching for such subtle changes in pressure takes perseverance. Calculating interconnected permeability by a single equation and determining the geometry of a channel by simple algebra makes the effort rewarding.
Three examples are presented to show how the following equations can be used to determine interconnected reservoir characteristics. Although the data is real, it refers to different fields, the interpretation of which is yet to be finalised. For this reason they are referred to as hypothetical cases A, B and C. These were selected because of the high frequency and the excellent quality of the data.
In oil field units:
Historically, running large diameter surface and intermediate casing in the shallow sections of a well with a high build rate and inclination has proven to be very challenging, with a high risk of getting stuck off bottom. At the same time, with limited drilling margins, it has become important to be able to successfully set large diameter casing under these conditions to enable the well to reach target objectives and/or avoid subsurface hazards. A comprehensive analysis reveals that a major contributing factor to the difficulty of running large diameter casing is due to the large end loads resulting from the high inherent stiffness of the casing as it is bent through doglegs or ledges. Finite element analysis indicated that these forces were high enough to cause the shoe to dig in to softer formations, and that the end forces increased substantially as casing size and weight increased, or as dogleg severity and inclination increased. A fairly simple solution was identified: a composite flexible shoe run at the bottom of the casing reduced the side loads at the bottom of the casing when running into the hole. Effective communication and cooperation between designer and operator allowed for a product that was thoroughly tested and examined from an operational standpoint to identify risks and address possible failure modes. Smaller tools were also proven out in higher build rate horizontal wells prior to running in a higher cost deepwater environment. Several case histories are presented that demonstrate the ability to run 18, 16, and 14-inch casing smoothly to target depth through build sections with doglegs of more than 4 /100ft, in soft formations, and to inclinations of more than 60 using a composite flexible casing shoe. The ability to reliably set large diameter casing through build sections and into high inclination wellbores expands the envelope of design possibility when planning deepwater wells.
For over fifty years, reservoir development around the world has covered different reservoir types and environments with vast technology, expertise and a growing variety of approaches. However, the predominant challenge from which a myriad of other field development issues arise has been on how to accurately characterise reservoir parameters because the obtained results are largely associated with uncertainties due to subsurface geological complexities. This paper focuses on the evolving advances and current practices in reservoir uncertainty modelling and gives insight into the future trends. This work critically examines the foremost statistical reservoir uncertainty analysis approaches, the current probabilistic and stochastic uncertainty modelling workflows which are typically based on various numerical models, and the very recent development of embedding some artificial intelligence algorithms (which include genetic algorithms, artificial neural networks, Bayesian networks amongst others) in reservoir uncertainty modelling, which now points to a future of using more sophisticated machine learning systems for achieving reservoir models and parameters with higher confidence. These evolving trends and approaches are discussed in more detail in this paper; with an in-depth analysis of the associated workflows, fundamental principles, strengths, weaknesses, robustness and economics of each approach. Also, reconciliation between the statistical, probabilistic, stochastic and artificial intelligence methods present a deep insight into the prospects of using artificial intelligence for optimising the modelling of reservoir uncertainties beyond the capabilities of conventional methods. Thus saving time and cost by quantifying the uncertainties in reservoir properties as well as regenerating new best-fit reservoir attributes using the robust uncertainty analysis networks and the pattern-recognition ability of machine learning networks. Hence, this paper presents a comprehensive review of the various uncertainty analysis methods, and also analyses the confidence of artificial intelligence applications which are increasingly pushing the frontiers to improved uncertainty modelling.
The initial reservoir fluid distribution in the Prudhoe Bay Reservoir, Alaska, consisted of relatively planar gas-oil and oil-water contacts. These contacts were soon perturbed by production as well as water and gas reinjection. Understanding the current reservoir fluid distribution and the movement of fluids in response to reservoir depletion mechanisms is key to optimizing and maximizing recovery.
Historically, the focus of much of the successful cased hole surveillance effort in the Gravity Drainage area of Prudhoe Bay has been directed at tracking the movement of the gas-oil contact and quantifying the remaining oil bypassed by gravity drainage processes. Forward modelling of pulsed neutron tool attributes has been employed to enable gas saturation quantification. Recent introduction of memory Multi-Detector Pulsed Neutron technology has enabled the quantification of bypassed oil in horizontal wells using coiled-tubing. Selective perforation has been used to access undrained oil.
In the Waterflood area of Prudhoe Bay, it is a challenge to use conventional sigma logs to distinguish between oil and water due to the relatively low and variable formation and injection water salinity. Consequently, continuous and multiple passes and stationary Carbon- Oxygen logs have been employed to identify bypassed oil.
In areas of the field where gas, oil and water columns exist in a single wellbore, both Carbon-Oxygen and Multi-Detector Pulsed Neutron nuclear attributes are combined together using a novel three phase interpretation technique to quantify oil, gas and water saturation. The technique has been applied in a number of Prudhoe Bay wells to enhance understanding of the fluid distribution and to design perforation strategies to maximize offtake in existing cased hole wells.
Case studies of each scenario illustrate the use and integration of Carbon-Oxygen and Multi-Detector Pulsed Neutron attributes to identify bypassed oil.
Gim, HwanSeok (PartDB Co., Ltd.) | Song, DuckYong (PartDB Co., Ltd.) | Hwang, JinSang (PartDB Co., Ltd.) | Hwang, Hojin (Korea Research Institute of Ships & Ocean Engineering) | Park, YC. (The Williams Companies)
Oil majors have operated Offshore Platforms in more than 25 years and they need to evaluate the options of life extension or decommission over the computing residual life. In order to manage this trend, DNVGL and ABS are reinforced both engineering services and software with the expectation for the expansion of the market based on Regulatory requirements. When considering offshore platforms lifetime management, the platforms age and degradation or deterioration loads based on a specific environment needs to be regarded.
This study explains the trend of life time management in Oil & Gas Industry, especially for Offshore Platforms, and introduces a Condition based maintenance (CBM) system to integrate information related to diagnosis, assessment, prognosis and maintenance for the offshore platform’s state on the basis of Engineering Data comparison methodology.
With a traditional approach, it took months to make a report for the behavior based load analysis, based on data obtained from IMMS (month / quarter / half year / year). With the CBM concept system, especially Data comparison method, Design, Operation and Maintenance department can analyze fatigue life and predict the residual life within a week so that all interested parties can reduce costs and time through an effective decision process.
I have just returned from the 2014 SPE Annual Technical Conference and Exhibition (ATCE) in Amsterdam, which was well run, well attended, and chock-full of interesting information for facilities engineers. In Europe for only the second time in SPE’s history, the conference drew people from all over the world, covered global themes, and focused on the triumphs, challenges, and remaining opportunities for the North Sea.