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.
Africa (Sub-Sahara) ExxonMobil subsidiary Esso Exploration Angola has started oil production at the Kizomba Satellites Phase 2 project offshore Angola. The project involves the development of subsea infrastructure for the Kakocha, Bavuca, and Mondo South fields. Mondo South is the first field to begin production, and the other two satellite fields will follow later this year. The goal is to increase Block 15's production to 350,000 BOPD. Esso (40%) is the operator with BP Exploration Angola (26.67%), Kosmos Energy discovered gas at the Tortue West prospect in Block C-8 offshore Mauritania.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
As interest in time lapse seismic grows, particularly in the application of CO2 sequestration and enhanced oil recovery, it has become increasingly important to be able to translate seismic parameters into values that can be used by geologists and engineers to quantify rock properties and volumes of fluids in the ground. Relating the seismic parameters to specific variables of interest, such as saturation, is primarily the key goal in this kind of work. CO2 is a unique liquid, and is typically injected into reservoirs at a super critical state, making its thermodynamic properties a hybrid of liquid and gas. Liquid CO2 is difficult to distinguish from water, as its density and viscosity are very similar, thus the seismic response is similar. Alternatively, gas CO2, like hydrocarbon gas, is difficult to detect due to the fact that a small concentration of gas creates a large seismic response, making it difficult to determine when there is anything under 90% gas CO2. While some portions of the reservoir may be flooded to this extent, it makes saturation analysis particularly difficult, even when all things otherwise are assumed equal between two time lapse seismic data sets (this in and of itself is a rarity). Thus, we use the capillary pressure equilibrium theory method in order to take advantage of the supercritical CO2 thermodynamics properties and build a reservoir model that mimics the physics of fluid invasion due to capillary forces. Due to the clean and higher porosity nature of the Sleipner formation, we can make the assumption that there are not significant rock frame changes throughout the field. This assumption lets us create a capillary pressure model, which is driven by the interaction of the fluids themselves, and which we will then use to interpret corresponding Sleipner time-lapse inversion results for fluid content. Our study finds that although uniform at higher concentrations of CO2, the Sleipner field model appears closer to that of a slightly patchy fluid distribution at lower concentrations of CO2. This change in fluid distribution as saturation changes is uniquely captured via the capillary pressure equilibrium theorem method, and must be a-priori assumed when using other methods.
Presentation Date: Wednesday, October 19, 2016
Start Time: 4:00:00 PM
Presentation Type: ORAL
Nes, Olav-Magnar (Det Norske Oljeselskap ASA) | Boe, Reidar (SINTEF Petroleum Research) | Sonsteboe, Eyvind F. (SINTEF Petroleum Research) | Gran, Kjetil (Det Norske Oljeselskap ASA) | Wold, Sturla (Det Norske Oljeselskap ASA) | Saasen, Arild (Det Norske Oljeselskap ASA) | Fjogstad, Arild (Baker Hughes A/S)
Severe borehole-stability problems were encountered in a recent exploration well in the Norwegian North Sea. The problems occurred when drilling through Tertiary shale sections interbedded with permeable sand layers. Drilling was initially performed with water-based mud (WBM). However, because the section target was not able to be reached after more than 2 weeks of operation, the section was plugged back, and a sidetrack was drilled with an oil-based mud (OBM) without encountering major operational problems. On the basis of the post-drill analysis of drilling data, well logs, drill cuttings, and borehole cavings sampled from the well, this paper describes how the complex combination of drilling fluid salt concentration and geological constraints may be used to ensure successful future drilling operations in this part of the North Sea.Cuttings and preserved cavings collected during the drilling operation were selected from several depth intervals identified as potentially troublesome from drilling experience and log data. The determination of cuttings mineralogy enabled a better prediction of how the time dependency of the stable drilling-fluid-density window is influenced by an interaction between the shale and the drilling fluid. Mechanical strength is a key input parameter when predicting borehole stability. Dedicated rock-mechanical punch measurements on cavings were used to confirm the prediction of strength from log data alone. The examination of caving surfaces revealed the possible presence of in-situ-fractured rock. Such fractures would require special measures while drilling to maintain stability. Subsequently, a borehole-stability sensitivity analysis was performed that focused on time-dependent stability in the shale formations.The analysis used cuttings and cavings properties and logs as input. In particular, the modeling showed how the optimal potassium chloride (KCl) concentration in the drilling fluid changes with depth. The modeling further identified a relatively large sensitivity toward borehole inclination--even at fairly small inclinations. This paper thus illustrates the significance of properly accounting for rock-mechanical aspects when planning new wells.
Cockram, Mark Andrew (BG Group plc) | Ritchie, Allan Fraser (Schlumberger) | O'Keefe, John (Smith Bits, a Schlumberger Company) | van der Laan, Rene (Smith Bits, a Schlumberger Company) | Sundfoer, Erik (Smith Technologies) | Larsen, Olav (Schlumberger) | Kleimeer, Peter (M-I Swaco) | Rapp, Tom (The University of Aberdeen) | Shotton, Peter (Smith Services, A Schlumberger Company) | Gjertsen, Ole Jacob
To efficiently develop reserves in the Norwegian North Sea, the operator must drill a challenging 12¼?? directional borehole through a Chalk formation with high stick-slip potential. In Gaupe North, a negative vertical section was required in the initial kickoff to properly line up the well path before entering the reservoir target. The reservoir is comprised of channel/sheet sandstones interbedded with shale sequences with different pressure regimes and nearby reservoir depletion issues. The 8½?? wellbore must penetrate an unstable organic shale just above the reservoir, infamous for causing hole stability problems and stuck pipe events. The regulatory agency requires this shale to be drilled in an 8½?? section, requiring long exposure time, which increases risk for hole problems when running the production liner. The objective was to efficiently drill these trouble-zones and deliver two horizontal producers in a cost effective manner using an integrated engineering solution.
To achieve the objective, a sophisticated multidisciplinary approach was employed including: bit/BHA offset analysis to reduce stick-slip in the chalk; BHA/RSS and drilling fluids modeling/planning; and drilling parameter plots to identify optimum RPM/WOB. Also, a real-time parameter analysis system was deployed to optimize ROP without compromising hole cleaning or well integrity.
The synergy provided by a fully integrated service provider increased drilling performance and was a major contributor to the success of the Gaupe wells performance. Well 6/3-A-1H broke the previous Rushmore index for subsea development wells in the region and set a Norwegian record for wells in this class. Both wells (15/12-E-1H & 6/3-A-1H) achieved positive P10 curves and saved a total of 18 days vs AFE. Compared to an analogous UK North Sea field, significant increases in ROP were achieved resulting in the wells being drilled 20+ days faster than benchmark. The average increases in ROP for the two Gaupe wells were approximately 146%, 47% and 148% in the 17½??, 12¼?? and 8½?? sections respectively.
Nes, Olav-Magnar (SINTEF Petroleum Research) | Boe, Reidar (SINTEF Petroleum Research) | Sonstebo, Eyvind Frode (SINTEF Petroleum Research) | Gran, Kjetil (Det Norske Oljeselskap ASA) | Wold, Sturla (Det Norske Oljeselskap ASA) | Saasen, Arild (Det Norske Oljeselskap ASA) | Fjogstad, Arild (Baker Hughes Inc.)
Severe hole stability problems were encountered in a recent exploration well in the Norwegian North Sea. The problems occurred when drilling through Tertiary shale sections interbedded with permeable sand layers. Drilling was initially per-formed with water based drilling fluid. However, being unable to reach the section target after more than two weeks of operation, the section was plugged back and a sidetrack was drilled using an oil based drilling fluid without encountering major operational problems.
On the basis of the post-drill analysis of drilling data, well logs, drill cuttings and borehole cavings sampled from the well, this paper describes how the complex combination of drilling fluid salt concentration and geological constraints may be utilized to ensure successful future drilling operations in this part of the North Sea.
Cuttings and preserved cavings collected during the drilling operation were selected from several depth intervals identified as potentially troublesome from drilling experience and log data. Determination of cuttings mineralogy enabled better prediction of how the time dependency of the stable drilling fluid density window is influenced by interaction between the shale and the drilling fluid. Mechanical strength is a key input parameter when predicting borehole stability. Dedicated rock mechanical punch measurements on cavings were used to confirm the prediction of strength from log data alone. Examination of caving surfaces revealed the possible presence of in-situ fractured rock. Such fractures would require special measures while drilling to maintain stability.
Subsequently a borehole stability sensitivity analysis was performed focusing on time dependent stability in the shale formations. The analysis used cuttings and cavings properties and logs as input. In particular, the modelling showed how the optimum KCl concentration in the drilling fluid changes with depth. The modelling further identified a relatively large sensitivity towards borehole inclination - even at fairly small inclinations. This paper thus illustrates the significance of properly accounting for rock mechanical aspects when planning new wells.
Hadia, Nanji (Norwegian University of Science and Technology) | Lehne, Havard Heldal (Norwegian University of Science and Technology) | Kumar, Kanwar G. (Norske Shell E&P A/S) | Selboe, Kristoffer Andr (Baker Hughes Inc) | Stensen, Feb Åge (Norwegian University of Science and Technology) | Torsater, Ole (NTNU)