Hadi, Farqad (Petroleum Engineering Department, Baghdad University) | Albehadili, Ali (Iraqi Drilling Company) | Jassim, Abduihussein (Najaf Oil Fields) | Almahdawi, Faleh (Petroleum Engineering Department, Baghdad University)
Formulating a prediction tool that can estimate the formation permeability in uncored wells is of particular importance for many applications related to reservoir simulation and production management. Although formation permeability can be obtained from a laboratory or from a reservoir, core analysis and well-test data are limited due to cost and time-saving purposes. A major challenge of previous methods is that they are required other parameters to be previously computed such as porosity and water saturation. In addition, they are affected by the uncertainty that introduced by the cementation factor and saturation exponent. This study presents two prediction methods, multiple regression analysis (MRA) and artificial neural networks (ANNs), to estimate formation permeability using conventional well log data.
The prediction methods were demonstrated by means of a field case in SE Iraq. The study uses core/well log data from Mishrif reservoir which is mainly composed of carbonate (limestone) formations. Two traditional methods were reviewed and presented for permeability determination. These methods are the classical method and the flow zone indicator (FZI) method.
At the same porosity, the results showed a wide range of formation permeability prediction. This result gives a special attention to the assumption that the relationship between permeability and porosity is generally unique in carbonate environments. The deep lateral log resistivity appears to be more conservative in the permeability function rather than other parameters, followed in decreasing order by bulk density, sonic travel time, micro and shallow resistivities, and shale volume. Although the presented models based on RA and ANNs resemble to be closely in determining the formation permeability, the correlation coefficient of ANNs was found to be higher than that obtained from RA, which indicated that the ANNs is more precise than RA. The comparison among previous methods shows the superiority of the FZI method rather than the classical method. However, core porosity and permeability should be previously determined to apply FZI method. This study presents efficient and cost-effective models for a prediction of permeability in uncored wells by incorporating conventional well logs.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Khan, Muhammad Hanif (Independent) | Maqsood, Tahir (Tullow Pakistan) | Jaswal, Tariq Majeed (Pakistan Oilfield Ltd) | Mujahid, Muhammad (Spec energy DMCC) | Malik, M. Suleman (Qatar Petroleum) | Jadoon, Ehtisham Faisal (UEP Pakistan) | Hakeem, Uray Lukman (Qatar Petroleum)
This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East. The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform. The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age. In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area. The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.
Arctic hydrocarbons were written off when oil prices dropped. Yet, the Arctic is diverse, and there are some fields with attractive economics. Since circumpolar littoral states do not subsidize hydrocarbon resource developments, operators must confirm fields’ financial viability in a global trading context, that is if governments let them. The objective of this paper is to assess to what extent circumpolar governments facilitate hydrocarbon exploitation in their Arctic areas.
The paper will assess governments’ facilitation by making a qualitative comparison along two axes: (i) ease of use of safety regulations (ii) general investment friendliness.
There is some debate about
Maritime activities apparently have an implicit license to operate. Not so for hydrocarbon developments. Such resource development is firmly anchored inside the national regulatory remit. Some countries have a liberal, permissive approach to resource developments, while other countries are more restrictive and precautionary. What is the overall regulatory situation today?
Safety regulatory developments are moving ahead, expecting further resource developments. Political discussions in different countries may still lead to different investment climates in each country.
Where companies should invest is not part of this presentation. Arctic resource developments take place in all the countries addressed in this paper, so Arctic hydrocarbons indeed have a place in today's energy markets. All countries assessed could still improve further – to a greater or lesser degree – their respective investment climate for such resource developments.
In this work, we solve the seismic inversion problem of obtaining an elastic model of the subsurface from recorded seismic data using a convolutional neural network (CNN). For simplicity we consider a 1D layered earth model and normal incidence seismic data. We systematically test the robustness of the network in predicting P-impedance (Ip) of new, previously unobserved, earth models when the input to the network consisted of seismograms generated with (1) different source wavelets; (2) earth models that had different geostatistical spatial correlations; and (3) earth models that had different underlying rock physics relation than that in the training data. Results show that the CNN successfully predicts impedances generated with both variograms ranges on which it was trained and variogram ranges on which it was not trained. The CNN was able to predict with medium success samples generated with rock physics model parameters and source wavelet phase outside of the training range. The CNN was not able to predict either the training set or any of the testing sets in the presence of various source wavelet frequencies, showing the importance of knowing a-priori the value of the wavelet frequency when generating the synthetic seismic data. Overall, the CNN has shown great promise in predicting a high frequency impedance model from a low frequency seismic signal, given appropriate training data.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 204B (Anaheim Convention Center)
Presentation Type: Oral
This paper describes various sulfide inhibitor-testing techniques that have been applied to candidate products for the management of zinc sulfide (ZnS) and lead sulfide (PbS) in a gas/condensate field with a known relatively severe ZnS/PbS scaling problem. The paper presents sulfide static- and dynamic-test measurements along with thermal-aging results that show some encouraging results in terms of ZnS/PbS inhibition. The Glenelg field is a gas/condensate field discovered in 1999 by exploration; production began in 2006. Glenelg is located in the southern part of the central graben of the North Sea, and it is part of an area where there have been a number of gas/condensate discoveries within Jurassic and Triassic (Fulmar) sandstone formations. For a geological description of the field, please see the complete paper.
The application of chemostratigraphy to problems in modern and ancient environments has a long and successful history. In particular, the use of high-resolution X-ray fluorescence (XRF) spectrometry for studying the elemental content of core and rock at the sub-millimeter scale to understand provenance, grain size, paleoredox state, terrigenous influence, and other aspects of strata is well documented in paleoclimatology literature.
ABSTRACT: We use an evolutionary geomechanical model to study stress and deformation in sediments during the emplacement of a frontal-rolling salt sheet. We show that overturned-roof sediments develop high differential stresses and plastic strains. We illustrate that these high plastic strains may allow roof layers to overturn and fold below the advancing salt. Sediments fail during roof overturn but regain strength as they get buried below salt. We discuss that sediment strength and failure depend on the overall evolution of the salt system. We show that the salt-base geometry can provide a first order estimation of the level of shear as well as of the decrease in least principal stress below salt. We build our large strain models in the finite element program Elfen. We model salt as solid viscoplastic and sediments as poro-elastoplastic materials. Overall, our evolutionary models provide insights into the mechanics of salt-sheet emplacement, identify potential drilling hazards and help understand stress and deformation of basin sediments near salt.
A salt sheet is an allochthonous salt body sourced from a salt diapir, and whose breadth is several times greater than its maximum thickness (Jackson and Hudec, 2017). Salt sheets are a common feature in salt systems around the world, including a very strong presence in the Gulf of Mexico (Jackson and Hudec, 2017).
Salt is a solid viscous rock that cannot sustain deviatoric stresses over geologic time (Urai and Spiers, 2007). When subjected to differential stresses, for example by differential sedimentation or tectonic loading, salt flows until its stress state is uniform. During this process, it may form diapirs and salt sheets. In particular, salt sheets commonly form when the upward rise of the salt in a diapir is much faster than the local sedimentation rate (Hudec and Jackson, 2006).
The advance of a salt sheet imposes strains onto roof and underlying-basin sediments; hence, it perturbs their state of stress. Indeed, shear zones and high pore pressures are often encountered below salt (Dusseault et al, 2004, Harrison et al, 2004, House and Pritchett, 1995, O’Brien and Lerche, 1994, Willson et al, 2003, York et al, 2009, Zhang, 2013). As a result, exiting the base of a salt sheet is one of the most dangerous moments in subsalt drilling. There is a lot of uncertainty in evaluating the present-day stress, pore pressure, and deformation state of subsalt sediments because seismic imaging is poor immediately below salt (Israel et al, 2008, Jackson and Hudec, 2017, Perez et al, 2008). Under these conditions, one of the most plausible ways to predict stress and pressure anomalies subsalt is to understand how salt was emplaced and how it interacted with basin sediments during its emplacement.
Subsea services company Kreuz Subsea mobilized the new-build dive support vessel (DSV) Kreuz Challenger as part of its 7-year contract with Brunei Shell Petroleum Company Sdn Bhd (BSP). The contract, which runs until 2022, includes supporting BSP with inspection, repair, and maintenance services to be carried out on offshore oil and gas structures in Negara Brunei Darussalam's territorial waters. The structures include drilling platforms, production stations, mini-production stations with combined drilling and production functions, gas compression stations, vent jackets, two single buoy moorings, Brunei’s LNG loading jetty, and various pipelines—typically in depths of up to 80 m. The DP-2 DSV Kreuz Challenger was purpose-built by the Vard shipyard in Norway to meet BSP’s standards and requirements, as well as the current industry-recognized diving system assurance, DNV class standards, and IMCA regulations. The vessel can accommodate 105 personnel and is equipped with a 100-ton active heave compensation crane, a 12-man saturation diving system, and a self-propelling hyperbaric lifeboat.