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.
Salehabadi, Manoochehr (Shell UK Exploration & Production) | Susanto, Indriaty (Shell UK Exploration & Production) | Prin, Cindy (Shell UK Exploration & Production) | Freeman, Christopher (Shell UK Exploration & Production) | Laird, Rebecca (Shell UK Exploration & Production) | Gernnaro, Sergio De (Shell UK Exploration & Production) | Forsyth, Gatsbyd (Shell UK Exploration & Production) | Doornhof, Dirk (Nederlandse Aardolie Maatschappij B.V.)
Strong reservoir pressure depletion after years of production in a high pressure, high temperature (HP/HT) oil field in the UK Central North Sea led to reservoir compaction and stress changes in the overburden, which consequently had an impact on the fracture gradient profile. The understanding of the current fracture gradient is essential as it is one of the two key process safety inputs for further drilling or abandonment design. Besides ensuring hydrocarbons are kept within the reservoir/subsurface by assessing the caprock integrity, the ability to accurately estimate the fracture gradient range can potentially provide significant savings in the design and concept select phases, especially for HP/HT fields as most investments are very capital intensive. Stress changes in the overburden rock due to reservoir compaction ("stress arching effect") can be observed from the Time Lapse (4D) seismic data as a velocity slow down due to overburden stretching/ expansion. An integrated study was conducted by developing a 3D geomechanical model and coupling with 4D seismic data to assess the current fracture gradient in the overburden, specifically in the caprock. The results of this study show that overburden weakening is strongest at the top of the reservoir and extends up to mid overburden. The lateral extent of the weakening is confined by the area of the depleted reservoir. In this paper, we demonstrate the benefits of understanding the current fracture gradient, both for abandonment design by optimising the number of cement plug isolations and their location as well as for assessing the caprock integrity during long term abandonment.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
The ability to predict the impact of faults on locating the remaining Hydrocarbon (LTRH) is critical to optimal well placement, reservoir management, and field development decisions, particularly relevant for cost effective management of North Sea assets. Tools and techniques to realistically differentiate between sealing and non-sealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporates detailed geology and reservoir engineering to understand production behaviour of a complex faulted high pressure high temperature (HPHT) field in the North Sea. The fault architecture divides the field into 5 lateral compartments. Historically, fault transmissibility from lateral connectivity between compartments and changes of this property with depletion was recognized as a key subsurface uncertainty.
Oil-bearing Pentland and Skagerrak are key producing reservoirs of interest; Skagerrak reservoir with an average reservoir permeability of 50mD is the focus of the study. The initial reservoir pressure and temperature are 12500psi and 3400 F respectively. Production started in 1998 from well 22/24D-10 (southern fault block) and after producing slightly more than 1MMstb, rapid decline in reservoir pressure (~6000 psi) signifying no pressure support was observed. In 1999, a flattening of the pressure that extended to 2006 was observed. From Material Balance work, flattening of pressure was not expected until below bubble point if there is no change in connected Stock Tank Oil Initially in Place (STOIIP). Therefore, one hypothesis is that the observed pressure flattening could be as a result of cross fault flow that changed the connected dynamic STOIIP as a result of draw-down during production. Another hypothesis is that recharge could be through the aquifer. This study shows that fault seal failure is the most likely mechanism for pressure support.
Three main techniques used for investigating dynamic fault seal breakdown are presented. This includes proprietary Petrel FTM plug-in tool, production analysis and deconvolution. Static evaluation of faults using the Shell tool suggests initial sealing nature at initial conditions and the ability for the fault to breakdown given high enough pressure differential. Production analysis identified the weak faults. Deconvolution of the rate and pressure history reveals signature consistent with breakdown of a fault. The distance extracted from deconvolution is consistent with that from static evaluation. Also, 4D seismic signal is consistent with all interpretation of fault seal breakdown. Result shows that the first three compartments in the southern part of the field have been depleted and that there is across fault flow at or below 6000psi capillary threshold pressure.
It will be shown that using well test analysis technique; dynamic fault seal failure can be properly understood. It is hoped that this paper will guide and improve a petroleum engineer’s ability to account for dynamic nature of fault Transmissibility Multipliers during dynamic simulations.
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.