Yang, Zhiyong (Keppel Floatec) | Bucchini, Matteo (Navalimpianti Spa) | Frontera, Raffaele (C-Job Naval Architects) | Basu, Roger (Roger Basu & Associates Inc.) | Baxter, Gail (Consultant) | Sielski, Robert (Consultant) | Karr, Dale (Universit of Michigan)
Structural finite element analysis (FEA) is routinely used in the design of modern ship and offshore structures. The benefits of FEA are apparent when used proficiently, but it can yield incorrect and misleading results when misused. There are certain types of errors in FEA that are unfortunately not that rare, but many of these errors can be avoided if clear and direct advice is provided to the analyst. SNAME Hull Structure Panel (HS3) aims to help analysts recognize the limitations of FEA tools and provide guidance on how to overcome them. A generic semisubmersible model is studied in order to demonstrate the simplification of the real structure in an FEA model, studying beam idealization in ship/offshore structure FEA, along with how to deal with the global and local loading. The effect of modeling geometry discrepancy is identified with numerical examples to illustrate the benefits of the guidelines. When a local model is built and boundary conditions are to be applied, displacement from the global model is often used to transfer the global loads. The difference between a detailed shell local model and the simplified coarse beam/shell global model requires the use of so-called rigid elements, such as RBE2/RBE3 in the commercially-available program ANSYS, which was used in developing these guidelines. Other than displacement, the local model may be analyzed using force boundary conditions obtained directly from the global model beam element internal forces. While the two methods are acceptable in the applications, there are issues with each of the methods. Theoretical formulation is used to show that either of the choices of boundary conditions could be established in order to solve the basic equation. However, a judicious process to deal with the boundary conditions will help analysts determine the best approach. An investigation of the effects of different methods is shown to illustrate the consequences. A summary of guidelines to these particular problems is presented. Future work is also discussed
In the Williston Basin, thin reservoirs coupled with large stimulation jobs result in large vertical hydraulic fractures and out-of-zone contribution of fluids to the wells. To understand the extent of vertical fracture growth and the source of fluids reaching the wellbore, the time-lapse elemental and isotopic composition of produced waters were compared with the in-situ pore water chemistry reconstructed from core analysis (residual salts analysis (RSA)) for a set of wells in Williams county, ND.
Residual salts analysis was performed on 28 core plugs from the Lodgepole (LP), Upper Bakken Shale (UBS), Middle Bakken (MB), Lower Bakken Shale (LBS), and Three Forks (TF). RSA data indicate that the sampled formations have distinct fingerprints, predominantly in terms of strontium abundance [Sr] and strontium isotopic compositions (87Sr/86Sr). Once baseline compositions for all formations were established, time-lapse produced water samples were taken from two lateral wells (1MB and 1TF; high-impact stimulation) proximal to the baseline RSA data. Time-lapse water chemistry from both lateral wells indicates that from initial flowback through 7 months of production >80% of the produced water is sourced predominantly from the TF with minimal water contribution from other formations. Large compositional changes in the produced water within this time-period are caused by operational disturbances and/or changes in flow rate.
Preliminary, these data suggest that high-impact stimulation results in large vertical hydraulic fractures that stay open for at least 7 months resulting in produced water being dominated by a TF source. Based on produced water data from older wells with lower-impact completions, the relative contribution of water from the TF diminishes over time indicating continued, but diminished communication with the TF. Results from this study also have implications about irreducible and critical water saturations, which both have critical impact in reservoir models. A comprehensive understanding of the origins of fluids from different subsurface storage units improves well stimulation and production programs and ultimately, well economics.
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
This paper presents a data driven approach to answer the question of whether premium, high strength white sand proppant, while more expensive than regional (brown) sand, is justified due to its alleged ability to make better producing wells. For this study, 739 horizontal wells with production, and stimulation data were used in a robust statistical approach to conclude that, for the most common set of well characteristics, white sand will produce a superior NPV weighted economic outcome than lower cost regional (brown) sand alternatives. While there are wells in this analysis that did not produce this robust conclusion of "white sand is better", none of them produced an outcome that "brown sand was better". Rather, several of the wells simply had results that were statistically inconclusive. This paper serves as a good example of what data are needed to perform such an analysis and the challenges of normalizing'first order effects' that dominate the influence on well productivity (TVD, lateral length, and proppant intensity) while attempting to ascertain the influence of'second order' factors such as Sand Type. Becoming familiar and adept at these analysis methods should facilitate the statistical verification of other second order effects on finding the optimal stimulation treatment.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.
Sawaryn, Steven J. (Consultant) | Wilson, Harry (Baker Hughes, a GE company) | Bang, Jon (Gyrodata Incorporated) | Nyrnes, Erik (Equinor ASA) | Sentance, Andy (Dynamic Graphics Incorporated) | Poedjono, Benny (Schlumberger) | Lowdon, Ross (Schlumberger) | Mitchell, Ian (Halliburton) | Codling, Jerry (Halliburton) | Clark, Peter J. (Chevron Energy Technology Company) | Allen, William T. (BP)
The well-collision-avoidance separation rule presented in this paper is a culmination of the work and consensus of industry experts from both operators and service companies in the SPE Wellbore Positioning Technical Section (WPTS). This is the second of two papers and complements the first paper, SPE-184730-PA (Sawaryn et al. 2018), which described the collision-avoidance management practices. These practices are fundamental in establishing the environment in which a minimum allowable separation distance (MASD) (in m) between two adjacent wells can be effectively applied. A standardized collision-avoidance rule is recommended, complete with parameter values appropriate to the management of health, safety, and environment (HSE) risk, and benchmarks for testing it. Together, these should help eliminate the disparate and occasionally contradictory methods currently in use.
The consequences of an unplanned intersection with an existing well can range from financial loss to a catastrophic blowout and loss of life. The process of well-collision avoidance involves rules that determine the allowable separation and the management of the associated directional planning and surveying activities. The proposed separation rule is dependent on the pedal-curve method and is expressed as a separation factor, a dimensionless number that is an adjusted center-to-center distance between wells divided by a function of the relative positional uncertainty between the two. The recommended values for the rule’s parameters result from a comparison of various industry models and experience. The relationships between key concepts such as the MASD and allowable deviation from the plan (ADP) are discussed, together with their interpretation and application. The dependency on the error distributions of the survey-instrument performance models used to establish the tolerance lines is also discussed.
The consequences of implementing a standardized separation rule across the industry are far-reaching. This affects slot separations, trajectories, drilling practices, surveying program, and well shut-in. We show how the MASD can be related to a probability of crossing and being in the unacceptable-risk region of an offset well. We show why this qualification is required for safe drilling practices to be preserved. Examples are presented in Appendices A through D to help the reader validate the calculations and the directional-drilling software necessary to perform them. The geometrical and statistical limitations of the methods are explained and areas are highlighted for further work. The methods outlined here, taken together with SPE-184730-MS, will improve efficiency in planning and executing wells and promote industry focus on the associated collision risks during drilling. The WPTS also supports the current development of API RP 78, Recommended Practices for Wellbore Positioning. Mathematical derivations or references are shown for all the calculations presented in the paper.
We introduce a novel well-logging method for determining more-accurate total porosities, fluid volumes, and kerogen volumes in shale-gas and shale-tight-oil wells. Improved accuracy is achieved by self-consistently accounting for the effects of light hydrocarbons and kerogen on the log responses. The logging measurements needed to practice this method are bulk densities, nuclear-magnetic-resonance (NMR) total porosities, and total-organic-carbon (TOC) weight fractions. The TOC weight fractions and the matrix densities, which are used to interpret the bulk density measurements, are both derived from geochemical-tool measurements.
Most unconventional shale-gas and shale-tight-oil reservoirs contain some nonproducible immobile hydrocarbons. When immobile hydrocarbons are present, our method requires prior knowledge of in-situ total water volumes. The water volumes can be estimated from dielectric-tool measurements. In special cases (e.g., in some mature shale-gas reservoirs) where no immobile hydrocarbons are present, a dielectric tool is not needed. In such cases total water volumes are outputs of the method.
We discuss the response functions in shale reservoirs for measurements of bulk densities, NMR porosities, and TOC weight fractions and derive exact self-consistent solutions to the response equations. The algebraic solutions are used to compute shale total porosities, fluid volumes, and kerogen volumes. The predicted shale total porosities and fluid volumes are corrected for light-hydrocarbon effects on the measured bulk densities and NMR porosities and for kerogen effects on the bulk densities. It is shown that significant errors can be made in log-derived shale total porosities if NMR porosities or density-log porosities are assumed to represent true-shale porosities without applying proper corrections.
We discuss the application of the method to the analysis of logging data acquired in a mature shale-gas well drilled in the Marcellus Shale in the northeastern United States and to data acquired in a shale-tight-oil well drilled in the Permian Basin in west Texas. A multifrequency dielectric tool is used to determine in-situ total water volumes in the tight oil well. The mature shale-gas reservoir does not contain immobile hydrocarbons, and, therefore, dielectric-logging measurements were not needed in this well. The results in both wells are shown to compare favorably with core data.
Al Dushaishi, Mohammed (Texas A&M International University) | Hellvik, Svein (National Oilwell Varco) | Aladasani, Ahmad (Consultant) | Alsaba, Mortadha (Australian College of Kuwait) | Okasha, Qutaiba (Kuwait Oil Company)
Data mining and Artificial Intelligence (AI) methodologies are underdeveloped in the oil and gas industry, despite the need to improve drilling performance and remain globally competitive in all capital-intensive projects.
Drilling companies allocate significant resources to improve well planning, drilling schedules and rig management. Well planning comprises of two main elements; drilling performance and the reduction of drill stem vibrations. Therefore, modeling methodologies such as drill string statics, dynamic tools and rate of penetration modeling are applied to determine the optimum bottom hole assembly (BHA) components and drill bit design. However, more attention is required on drill stem fatigue, non-productive time (NPT) and their impacts on drilling operations.
In this paper, Data Analytics (DA) is applied to drilling logs taken from three wells that recorded vibration readings from different geological stratification. In turn, the work in this paper establishes a relationship between drill stem vibrations and various measurement and logging data while drilling. Statistical regression and multivariate analysis were used to examine correlations of drilling parameters, including BHA assembly, to vibration data. Therefore, the results include a composite vibration model that describes the drilling stem vibration behavior as a function of drilling parameters, and geological formations.
Results of the vibration models built in this study indicate that the drill stem lateral vibration behaves parabolically as a function of the drill pipe length, length of drill collar, gamma ray (GR) response, and weight on bit (WOB). The analysis of drill stem vibration effect on the mechanical specific energy (MSE) was inconclusive for depths below 1350 meters. However, for depths above 1350 meters a strong correlation was observed to ROP.
The ‘Frontier Arctic’ offshore has been explored on and off since the 1970s, driven by oil price and areas open for leasing or licensing. While a widespread, future return is questionable, operators contemplating a return can benefit from past experience. Insight and perspective are provided on the technical and non-technical challenges and impact on the business challenge. Actions and opportunities to change the overall cost and non-technical business risk dynamic are discussed.
‘Frontier Arctic’ oil and gas resources have characteristics of 1) being located outboard of established offshore regions of oil and gas exploration and development, 2) having physical attributes of water depth and ice conditions that require the use of specialized equipment or measures to safely and cost effectively drill, and 3) having non-technical business risks with the potential for high business consequences. This loose definition includes much of the Alaskan Arctic, the Canadian Beaufort Sea, Greenland, the far northern Barents Sea, and much of the Russian shelf. The technical and non-technical issues associated with exploration drilling in these regions are well-established, but not necessarily well-integrated.
Interest in ‘Frontier Arctic’ exploration may be rekindled in the future depending upon commodity prices; however, the ability to make material cost changes are limited due to the nature of the technical challenge; and the "Frontier Arctic’ will likely remain a target for environmental activism. Furthermore, exploration drilling would need to take place now or in the reasonably near future if ‘Frontier Arctic’ resources are to have a chance of contributing to a future oil or gas supply shortfall. Notwithstanding, Arctic offshore exploration can be expected to continue in regions where cost and business risk can be managed such as the southern Barents Sea and nearshore Alaska Beaufort Sea region.
Sawaryn, Steven J. (Consultant) | Wilson, Harry (Baker Hughes, a GE Company) | Allen, William T. (BP) | Clark, Peter J. (Chevron Energy Technology Company) | Mitchell, Ian (Halliburton) | Codling, Jerry (Halliburton) | Sentance, Andy (Dynamic Graphics, Incorporated) | Poedjono, Benny (Schlumberger) | Lowdon, Ross (Schlumberger) | Bang, Jon (Gyrodata Incorporated) | Nyrnes, Erik (Equinor ASA)
The well-collision-avoidance management and principles presented in this paper are a culmination of the work and consensus of industry experts from both operators and service companies in the SPE Wellbore Positioning Technical Section (WPTS). This is not a new subject, but current guidance is disparate, company-specific, and occasionally contradictory. As a result, the guidance can be difficult to understand and implement. A further aim is to drive the standardization of the well-collision-avoidance rules, process, and nomenclature throughout the industry. Standardization improves efficiency and reduces implementation errors.
The consequences of an unplanned intersection with an existing well can range from financial loss to a catastrophic blowout and loss of life. The process of well-collision avoidance involves rules that determine the allowable well separation, the management of the associated directional planning and surveying activities, and assurance and verification. The adoption of a specific minimum-allowable separation rule, no matter how conservative, does not ensure an acceptably low probability of collision. Many other factors contribute, such as the level of compliance by office and rig personnel with collision-avoidance procedures, and the completeness and correctness of the directional database. All these factors are connected.
The material is split into eight sections, each dealing with a critical element in the collision-avoidance process. Examples are presented to highlight a good-implementation practice. This aligned approach will dispel some of the current confusion in the industry concerning well-collision avoidance; will improve efficiency when planning and executing wells; and will build industry focus on the associated collision risks when drilling. The WPTS is also supporting the current development of API RP 78 (not yet issued).
This is the first of two papers. The second paper (Sawaryn et al. 2018) covers the minimum-allowable separation rule and its application, assurance, and verification.