Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
The most important contributer to Improved Oil Recovery (IOR) on mature fields is drilling of infill wells. Managed Pressure Drilling (MPD) and Continuous Circulation System (CCS) techniques can be used for improved control of bottomhole pressure when drilling wells in depleted fields with narrow pressure windows, but rig heave is a challenge when drilling from floating drilling units. Rig heave, caused by sea waves, induces pressure oscillations downhole that may exceed the operational pressure window. These oscillations are called "surge & swab" and occur both during tripping in and out of hole as well as during drill pipe connections, when the topside heave compensation system used during drilling is disabled because the drill pipe is put in slips. Downhole choking was introduced as a method to reduce downhole pressure oscillations induced by the rig heave and the concept was tested in laboratory scale and using computer simulations (
This paper gives an overview of the surge & swab simulator, describing its capabilities and limitations. Data from drilling of a North Sea well is then used to validate the simulations made using the software. The well, used as example in this paper, was drilled conventionally from a floating rig. The downhole pressure variations recorded during three different drill pipe connections are compared with simulated downhole pressure. The simulations are based on the recorded rig heave as well as the actual drilling fluid, well design and drill pipe data. Results show that there is a good correlation between simulated and actual measured downhole pressure. The surge & swab simulation software is then used to simulate the same drilling pipe connections using three different techniques and combinations of techniques utilized for improved downhole pressure control: (1) Managed Pressure Drilling (MPD) (2) Managed Pressure Drilling combined with Continuous Circulation System (CCS) and (3) MPD combined with CCS and a downhole choke. Results show that rig heave-induced downhole pressure variations are reduced to a level which is considered acceptable for drilling a well with narrow pressure window for the last two cases, while utilization of backpressure MPD alone is not sufficient. The combination of MPD and CCS reduced surge & swab for two out of three connections. For the third and deepest connection, the surge & swab increased. The largest reduction in significant downhole pressure variations (43-68 % vs. conventional drilling for the three connections) occurs when MPD and CCS are combined with downhole choking.
Future work will consist of further developing the surge & swab simulator so that it will be possible to utilize it in well planning and as real-time decision support during drilling operations. The simulator will also be developed to include possibility of simulating various well completion operations such as running casings and liners. A prototype of the downhole choke is currently being tested at the mud loop of the Ullrigg test rig facility in Stavanger, Norway, and the next development phase consists of designing and building a complete downhole tool for testing in a well.
With an increasing focus on identifying cost-effective solutions to well design with a minimal impact on productivity, this paper will focus on an alternative to cesium (Cs) formate as the perforation fluid in the high-pressure/high-temperature (HP/HT) Gudrun Field operated by Equinor. Cs formate has been used with success for drilling and perforating many HP/HT wells. However, because of the significant cost of this fluid coupled with low oil prices, Equinor wanted to perform testing to assess the performance of an alternative oil-based mud (OBM) as a perforation fluid. In this paper we describe the extensive qualification testing that we have conducted, which includes coreflooding using representative plugs from Gudrun Field under downhole temperature and pressure conditions. In addition, eight API RP19B (2014) Section IV perforation tests have been conducted to compare the performance of the Cs formate with the OBM. These tests were undertaken using gas- and oil-saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows:
On the basis of the results of the coreflooding combined with the API RP19B (2014) Section IV testing, the OBM was selected as the perforating fluid for use on Gudrun Field. The perceived benefits of using the OBM were as follows:
Perforation modeling is described, and a comparison is made between this and the API RP19B (2014) Section IV tests. Finally, the well-startup experiences and the production data are presented, demonstrating the effectiveness of the OBM as a perforation fluid.
Chen, Guang (China University of Petroleum–Beijing) | Zhou, Hui (China University of Petroleum–Beijing) | Liu, Mingdi (China University of Petroleum–Beijing) | Tao, Yonghui (China University of Petroleum–Beijing) | Wang, Haiyang (China University of Petroleum–Beijing)
Elastic impedance inversion is an important prestack inversion method in reservoir prediction and fluid identification. Constrained sparse spike inversion (CSSI) used to be the most widely used method in poststack seismic inversion. Because of the relationship between the elastic impedance and the wave impedance, the CSSI can be directly applied to the prestack elastic impedance inversion. However, CSSI usually suffers from strongly ill-posed problem when using some local optimization algorithm, such as conjugate gradient (CG) method, and has a strong dependence on the initial model of reflection coefficient. Besides, conventional CSSI separately inverts the time locations and amplitudes of sparse-spikes, which increases the computational complexity. In this paper, we improve CSSI theory with a linear wave impedance constraint, which is named as LCSSI. We apply orthogonal matching pursuit (OMP) non-linear algorithm to linear constrained sparse spike prestack elastic impedance inversion. We derive a linear matrix equation from the cost function and use OMP algorithm to invert the sparse-spikes' time locations and amplitudes simultaneously. Due to OMP, this method can reduce dependence on initial model and obtain the inversion results precisely and quickly. Numerical examples indicate that our method can achieve a good performance even for noisy data, while the CG algorithm fails to get a desirable inversion result.
Presentation Date: Wednesday, October 19, 2016
Start Time: 8:00:00 AM
Presentation Type: ORAL
Depth is the most fundamental logging parameter, tying together the vast array of subsurface measurements made. Along-hole depth forms the basis of essentially all aspects of our downhole industry and is the common reference for all subsurface measurements.
Previous studies have shown that as along-hole depth increases there is an increasing spread of differences between wireline and driller’s depths. Logging while drilling (LWD) depths are based on driller’s depths. These LWD depths are often used to initially define along-hole events, and are taken as a reference to take early decisions and make public announcements. A source of depth error and uncertainty is the common practice of operators to take LWD depth as a final reference, to avoid modifying net-pay public statements made early based on LWD data. Subsequently recorded wireline depths are often different, with the difference being perceived as a nuisance, because all the depths announcements otherwise need to be revised. However, the real consequences of depth-determination shortcomings are often only seen long after drilling and logging the well.
This paper reviews the key methodologies used in wireline depth determination and outlines a technique for wireline depth elastic-stretch correction and for stick-and-pull (also called stick-and-slip) correction. The waypoint methodology is proposed as a method of closing the gap between the various elastic-stretch corrections used. The correction is based on surface and cablehead tension measurements. These operational techniques can be used by all wireline service providers in helping to improve consistency and accuracy in the correction of wireline depth for elastic stretch, particularly as applied in first primary logging (first run in hole). The techniques outlined take in account complications caused by long-reach wells with complex trajectories and tension regimes.
By reviewing the various methodologies used to determine wireline depth, it is hoped that at least the wireline side of the discussion can be understood. The paper is aimed at opening up the debate on how the industry should deliver depth—the essential single parameter that links all subsurface data together.
The paper does not address a number of related subjects, including the economic need for absolute and relative depth accuracy, driller’s depth measurement and correction, thermal correction of wireline depth, (initial) permanent deformation (also called plastic stretch or, incorrectly, inelastic stretch) of wireline cables, and wireline cable stretch-coefficient determination. Neither does the article include a discussion on uncertainty, a key component to measurement integrity. These issues are each subjects for further investigation and debate.
Antonsen, Frank (Statoil) | Barbosa, Jose Eustaquio Pampuri (Statoil) | Morani, Beatriz (Statoil) | Klein, Katharine (Statoil) | Kjølleberg, Marie (Statoil) | McCann, Andrew (Statoil) | Olsen, Per Atle (Statoil) | Constable, Monica Vik (Statoil) | Eidem, Morten (Statoil) | Gjengedal, Jakob Andreas (Statoil) | Antonov, Yuriy (Baker Hughes) | Hartmann, Andreas (Baker Hughes) | Larsen, David (Baker Hughes) | Skillings, Jon (Baker Hughes) | Tilsley-Baker, Richard (Baker Hughes)
Statoil faced significant well placement challenges while drilling the first development wells on the Peregrino field, offshore Brazil, resulting in lower sandstone contact and production than expected. Efficient drainage from the gravity flow sandstone on this heavy oil field requires a high level of sandstone contact. The need for a deeper azimuthal LWD-measurement was identified as necessary for Peregrino to increase sandstone content in the horizontals by improving the ability to steer within relatively thin sandstone bodies, or to identify and drill neighboring thicker sandstone bodies above or below the well trajectory.
Statoil started a technology collaboration project with Baker Hughes in 2011 to accelerate the development of an extra-deep azimuthal resistivity measurement to address the Peregrino well placement challenges. The first wells utilizing the new LWD technology were drilled in 2012, and the technology has been applied in more than 20 wells on Peregrino so far. This valuable experience is currently transferred to fields on the Norwegian Continental Shelf (NCS).
The extra-deep azimuthal resistivity (EDAR) tool enabled Statoil to avoid pilot holes for stratigraphic control and landing, and to enhance the proactive geosteering within the complex Peregrino reservoir sandstone, resulting in increased reservoir exposure and production. The extra-deep look-around measurements, sensitive to contrasts 20 m from the wellbore or more in favorable conditions, is bridging the gap between traditional wellbore measurements and seismic data; by integrating these data types, interpretation of the reservoir structure and geometry can be refined, resulting in better constrained reservoir models and an improved field development strategy.
This paper presents examples of extra-deep resistivity measurements from reservoir sections drilled on Peregrino to illustrate the technology development, well placement experiences and learnings pertaining to real-time interpretation and geomodel updates. The initial experiences from the Norwegian Continental Shelf will also be presented to explain how the technology works in various geological settings.
Bottom trawling activities can potentially influence pipeline design substantially. In order to evaluate the conservatism imposed by current standards, such as DNV-RP-F111, it is of interest to further study the interaction between trawl gear and pipelines. This paper presents results from simulating the pullover interaction that takes place when clump weights interfere with subsea pipelines. The nonlinear finite element software SIMLA has been utilized for the simulations. MARINTEK performed model tests for clump weight interference with pipelines on behalf of Statoil for the Kristin field development in 2004. These model tests have been replicated in a full scale SIMLA model, and numerical results are compared with the experimental ones. In addition to simulations of these idealized model test setups, simulations have also been performed for a realistic example flowline both in free span and resting on seabed.
McMillan, D. Nelson (Halliburton) | Lunde, Odd Halvard (Halliburton) | Mikalsen, Renate (Halliburton) | Mæland, Yngve (Halliburton) | Wroblewski, Tomasz (Statoil ASA) | Vatne, Åsgeir (Statoil ASA) | Dillner, Birgitte (Statoil ASA)
This paper describes the first field application of a high-pressure/high-temperature (HP/HT) organophilic clay-free invert emulsion fluid (OCF IEF) weighted with small-particle-sized (SPS) barite, qualification of which was achieved through extensive laboratory investigations (described elsewhere). The paper describes detailed observations of the fluid performance during first use (i.e., "critical first well application") on a Statoil-operated HP/HT field in the North Sea.
In the well selected for first application, finger-printing was performed so that behaviors of the 1.96-specfic gravity (sg) invert emulsion fluid (IEF) could be examined and recorded before entering the open hole. When in the open hole, observational tests were continued throughout the well. Before and after trips, fluid behavior and properties were monitored and recorded. Additionally, extensive fluid testing was conducted on the rig (rheology, HP/HT fluid loss, particle plugging test [PPT] static sag, and viscometer sag shoe test [VSST]). Before running stand-alone screens (SAS), screen flow-through tests were performed.
Extensive tests showed acceptable fluid performance within stringent, defined criteria at all times. When re-initiating circulation on several consecutive connections, pump ramp-up time was gradually reduced. No pressures above drilling equivalent circulating density (ECD) were observed at any time. While drilling, the ECD values were maintained well within the required values. No barite sag was observed on any occasion, even after 90 hours static or during a slow circulation rate test performed to simulate conditions likely to induce dynamic sag. Fluid loss control (PPT) was maintained within specifications through the addition of ground marble. A decrease of approximately 60% in fluid treatments compared to a conventional HP/HT IEF resulted in a reduction in chemical and logistical costs and manual handling. The well was drilled well ahead of plan, resulting in saved rig time. No issues were observed when running screens to total depth (TD) with the IEF. The well was easily brought on production after ~30 days, with the IEF being produced back to surface, consistent with expectations from the qualification laboratory testing undertaken at Statoil's laboratory facilities. Highly acceptable production rates were achieved, indicating minimal productivity impairment.
The efficient drilling of the well, along with being able to complete the well in the same IEF and not displace to brine, as was previously performed, resulted in substantial cost savings compared to other qualified solutions. This successful first application demonstrated that the well could be drilled and completed in the same fluid with an enhanced drilling performance and highly acceptable productivity outcome.
The introduction of formate-based drilling muds successfully addressed drilling challenges related to barite-weighted muds. The muds exhibited peculiar petrophysical properties that adversely affected log interpretation. First, the mud present inside the borehole and surrounding the tool required different environmental corrections; secondly invading mud-filtrate present inside the formation was difficult to account for. Because of the higher density, lower hydrogen index, and high gamma-ray readings associated with Na/K formate-based drilling fluids, for example, petrophysical analysis typically resulted in inaccurate mineralogy and pessimistic porosity and permeability estimates. Such estimates were also strongly dependent on the extent of invasion by the mud.
Two new approaches were developed to address these long-standing challenges in gas-bearing siliciclastic and carbonate sequences. Logging-while-drilling (LWD) time-lapse data acquisition makes it possible to track changes in log measurements between a first (drill) pass and a second (wipe) pass as mud filtrate invades the formation. In a first approach, these changes reflect the contrast in petrophysical properties between the mud filtrate and the displaced native formation fluids, and can be used to estimate the unknown petrophysical properties of such mud filtrate. In a second, geometric approach, the different measurements are considered to represent different axes in measurement space, and then the axes are rotated to reduce the number of rotated measurements affected by invasion to just one. This measurement is then discarded, and the remaining rotated measurements are used.
In all, up to six different petrophysical models from two different wells were compared. The results indicate a step change in petrophysical analysis in case of Na/K formate-based drilling fluids. They demonstrate how it is possible to build a robust but remarkably simple petrophysical model using only rotated nuclear measurements, with all of the following characteristics. The model is extremely stable as compared to more complex models. It requires neither knowledge of the Na/K formate mud-filtrate characteristics, nor knowledge of its volume. It does not require resistivity input, but consistently reproduces similar saturations when compared with models using resistivity as input. Data from the drill- and the wipe-pass produced identical results, independent of formation invasion.
Petrophysical analysis of well log data involves defining the petrophysical properties of the various minerals and fluids present underground, including the drilling fluids. Typically, some of these petrophysical properties are measured, whereas others are computed using established models, or calibrated against core, mud logging, formation testing and formation fluid sampling data.
Formation evaluation can become complex when the invading mud-filtrate properties are unusual, variable or unknown like in sodium potassium (Na/K) formate water base mud (WBM) environments. In these situations, computed reservoir properties are adversely affected and become strongly dependent on the formation invasion status.
The Permian age reservoir discussed in this paper, consists of highly unconsolidated heterogeneous sandstone sequences, saturated with condensate rich gas. From a drilling engineering perspective, the shales are often unstable, requiring high mud overbalance to maintain hole stability in wells with high inclinations, which resulted in recurrent differential sticking incidents. The use of formate based drilling fluids in this field, gained acceptance over time, primarily to minimize drilling problems.
The downside of formate muds, however, is that log data interpretation encounters serious challenges because of the uncertain petrophysical properties of the mud, affecting log measurements in two ways. The first are those effects related to the mud present inside the borehole and surrounding the tool, or so-called environmental effects. The second are those related to the invading mud-filtrate present inside the formation, resulting in pessimistic porosity, mineralogy and permeability estimates.
This paper shows how Na/K formate WBM filtrate effects can be identified and eliminated using Logging-While-Drilling (LWD) time-lapse data acquisition and analysis to provide time-independent logs in a manner that renders the logs immune to various mud-filtrate effects. These logs, together with a corresponding new petrophysical model, make it possible to do away with the mud-filtrate petrophysical properties, and to solve for porosity, mineralogy and fluid saturations from standalone nuclear measurements, irrespective of the formation invasion status.
Moreover, the results demonstrate how valuable LWD time-lapse data acquisition can be, and that data acquired while drilling – especially resistivity data in this instance – are important to validate this novel formation evaluation interpretation approach.
Volumetric Formation Evaluation (FE) describes the composition of underground formations in terms of volumetric percentages of minerals and fluids present. This starts by assigning different petrophysical properties – also called endpoints – to the minerals and fluids present. These endpoints describe what different measurements would read if only one mineral or only one fluid was present. The next step is to select a forward model – made up of so called mixing-laws – to describe what different measurements would read when the minerals and fluids are mixed in different volumetric percentages. Finally, actual log measurements are acquired and the forward model inverted to solve for the actual volumetric percentages of minerals and fluids present.