Copyright 2019 held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. ABSTRACT Today, many machine learning techniques are regularly employed in petrophysical modelling such as cluster analysis, neural networks, fuzzy logic, self-organising maps, genetic algorithm, principal component analysis etc. While each of these methods has its strengths and weaknesses, one of the challenges to most of the existing techniques is how to best handle the variety of dynamic ranges present in petrophysical input data. Mixing input data with logarithmic variation (such as resistivity) and linear variation (such as gamma ray) while effectively balancing the weight of each variable can be particularly difficult to manage. DTA is conceived based on extensive research conducted in the field of CFD (Computational Fluid Dynamics). This paper is focused on the application of DTA to petrophysics and its fundamental distinction from various other statistical methods adopted in the industry. Case studies are shown, predicting porosity and permeability for a variety of scenarios using the DTA method and other techniques. The results from the various methods are compared, and the robustness of DTA is illustrated. The example datasets are drawn from public databases within the Norwegian and Dutch sectors of the North Sea, and Western Australia, some of which have a rich set of input data including logs, core, and reservoir characterisation from which to build a model, while others have relatively sparse data available allowing for an analysis of the effectiveness of the method when both rich and poor training data are available. The paper concludes with recommendations on the best way to use DTA in real-time to predict porosity and permeability. INTRODUCTION The seismic shift in the data analytics landscape after the Macondo disaster has produced intensive focus on the accuracy and precision of prediction of pore pressure and petrophysical parameters.
The Slootdorp field has a complex structure with most reserves in Rotliegend sandstone, which is communicating with gas bearing Zechstein carbonates. The Rotliegend reservoir is bounded by a large fault, which might become seismogenic during depletion. A 3D geomechanical model was built, based on the faults and horizons in the geological model. Both the Rotliegend and Zechstein reservoirs were included in the model. The model was populated with geomechanical properties derived from logs, LOT's (leak off tests) and regional data on the stress field. Also, overburden properties from previous studies on nearby fields were used.
The pressure input was obtained from reservoir simulation. It is important to include the water leg pressure in the pressure input since the Rotliegend gas reservoir is in contact with an active aquifer. Pressure reduction drives the compaction of the reservoir, which induces stresses on the faults causing slippage. Since the water is quite incompressible, a large pressure reduction in the water leg may be caused temporarily by a rising gas water contact.
It turned out that slippage is not expected at the lowest gas pressure using a conservative estimate of the critical friction coefficient on the fault of 0.55. Sensitivity analysis on the most important input parameters was performed with a range that can be expected for such a field. The result was that the maximum critical stress ratio could range between 0.46 and 0.53 for the expected uncertainty of input parameters. The geomechanical modeling shows that an active aquifer has a dominant, mitigating effect on seismic risk, which can explain why many reservoirs show no seismicity in the Netherlands, although other effects could also play a role.
Understanding petrophysical properties well enough to make drilling decisions, particularly for tight gas can be a challenge. A new computer system aims to help analyze the extensive data involved. There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. One of these stranded tight gas fields, the Kew field, has been developed successfully with the use of a subsea well, horizontal drilling, and hydraulic fracturing.
With the purchase, the growing, privately-held Chrysaor Holdings will expand its UK North Sea production to 185,000 BOE/D. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. The latest example of the offshore sector's march toward automated wellbore construction will take shape later this year in the North Sea. Just 2 months after issuing more than a hundred licenses, the Oil and Gas Authority begins the process again for a whole new set of blocks. The company announced it would “initiate the process” of marketing its UK Central North Sea fields as part of a portfolio review.
Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
This course will discuss the practical state-of-the-art techniques of Volume to Value (VV) to help attendees assess exploratory deepwater offshore oil and gas prospects and quantify economic values of the prospects. Attendees will learn how to develop a preliminary field development plan for a given discovery prospect and estimate oil and gas recovery, wells required, and costs. They will also learn how to conduct economic evaluation for lease sales or farm-in opportunities. Upon completion of this course, attendees should be able to evaluate the commercial potential of original oil and gas in-place in exploratory blocks and develop preliminary field development plans. Attendees should also be able to obtain value of the opportunity in order to make the decision to go ahead and develop the field or walk away from it, as well as identify constraints in terms of geology and engineering that will make it viable or impede the realization of the project.
With a shallow water flow-back in excess of 200 bbl/hr from the Top Chalk formation during the 17½" section, the deviated exploration / development well "Well #4" was planned and drilled successfully with a jackup rig. The well was planned from a platform in the Southern North Sea.
The primary goal for the 17½" section was to safely drill to section TD, set casing and cement same with zero incident in a minimum amount of time while encountering shallow water flow.
The key challenges for this well were: Flowing Top Chalk Formation: The Top chalk formation flowed at all three previously drilled offset wells with 12.0 ppg EMW and approximately 200 bbl/hr. Several attempts to shut in the well and stop the flowing Top Chalk on the offset well "Well #1" failed. Obtaining regulatory approval from authorities, and commitment and acceptance by all involved parties to drill the well under flowing conditions. Hole cleaning and hole stability considerations when drilling with seawater Permanently shutting off the shallow water flow with a two-stage cementation. Rig uncertainty and general service market (in 2017): A new drilling contractor and drilling services not familiar with the peculiarities of operations in this area Safety, communication and human factor considerations for a potentially hazardous non-routine operation.
Flowing Top Chalk Formation: The Top chalk formation flowed at all three previously drilled offset wells with 12.0 ppg EMW and approximately 200 bbl/hr. Several attempts to shut in the well and stop the flowing Top Chalk on the offset well "Well #1" failed.
Obtaining regulatory approval from authorities, and commitment and acceptance by all involved parties to drill the well under flowing conditions.
Hole cleaning and hole stability considerations when drilling with seawater
Permanently shutting off the shallow water flow with a two-stage cementation.
Rig uncertainty and general service market (in 2017): A new drilling contractor and drilling services not familiar with the peculiarities of operations in this area
Safety, communication and human factor considerations for a potentially hazardous non-routine operation.
A collaborative well-planning and preparation process involving the operator drilling team, the drilling contractor and key service providers was critical to the success of the overall operation.
The team worked together to ensure all requirements, risk mitigating measures, lessons learned from previous operations and offset wells, and human factor considerations were incorporated in the execution program.
The well was successfully drilled to TD, evaluated, completed and flowed. The notable highlights from the top-hole drilling operation include: Fastest 17-1/2" phase compared to offset wells: drilling and casing operations completed in 94.25 hrs with the well flowing. Zero NPT in the 17-1/2" drilling phase: drilled 654 m in 37.5 hrs with an average ROP of 17.5 m/hr without any complications. Continuous monitoring and fingerprinting of the shallow water flow
Fastest 17-1/2" phase compared to offset wells: drilling and casing operations completed in 94.25 hrs with the well flowing.
Zero NPT in the 17-1/2" drilling phase: drilled 654 m in 37.5 hrs with an average ROP of 17.5 m/hr without any complications.
Continuous monitoring and fingerprinting of the shallow water flow
This paper describes the key planning considerations, preparations and creative solutions deployed to deliver the well. The lessons learnt will serve as a resource for planning future wells with similar challenges.
The IADC and SPE are committed to delivering a balanced agenda around Diversity and Inclusion, to support member companies as they strive to address the gap in the Oil & Gas Sector. In 2019 the SPE/IADC International Drilling Conference and Exhibition in The Hague will host a session that allows delegates to explore the challenges facing the industry and hear firsthand, how it can be addressed. This initiative aims to build on the efforts already being undertaken at individual company levels to attract, develop and retain female staff - especially in technical and senior management roles, and to remove barriers that may currently hinder or discourage women from rising through the ranks into leadership roles. The aim is to address the factors contributing to the gender gap and to advantage all companies, their owners and shareholders through the incremental performance and value that parity will generate. This is good for our people, good for our stakeholders, and good for our business. Whilst in 2017 the session focused on subjects arising from DAVOS 2016 namely Leadership, Aspiration, goal setting, STEM, recruitment and retention, corporate culture and work life balance, the panel now feel it is time to move the conversation forward with some hard-hitting topics that affect the lives of many. Make sure you join us for this special session in The Hague.