Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Many companies are now refocusing on play-based exploration, representing a return to our pre-1990s geoscience roots. Play-based exploration involves understanding all elements of the petroleum system for a given basin or play and then examining how, and more importantly where, those elements come together. This paper will examine the fundamental methods using examples across Asia and review step by step procedures of the play-based exploration process.
Kim, DongKyoon (Posco-Daewoo Corp.) | Kim, USU (Posco-Daewoo Corp.) | Lee, JungHwan (Posco-Daewoo Corp.) | Sur, YoungBin (Posco-Daewoo Corp.) | Song, JaeHak (Posco-Daewoo Corp.) | Park, JooSeon (Posco-Daewoo Corp.)
This paper presents how to identify a hotspot, i.e. the most critical interval with a localized high gas rate and to determine the reliable maximum gas flow rate by interpreting production logging and calculating the fluid velocity at completion screen. This reliable characterization is highly important to prevent any failure of cased-hole gravel pack screens from fine particles.
Generally, operators manage the gas well within allowable pressure draw down range. The rule of thumb for restriction on maximum recommended drawdown ranged from 500 psi to 1000 psi. However wells completed through sand control equipment completion might encounter sand face completion failure in the occurrence of extremely high velocity flowing hotspot zone near the screen or liner. Therefore it is necessary to pay close attention to the detection of hotspot zone using production logging interpretation. Moreover, calculation of the maximum gas rate based on gas velocity profile through the screen would determine the allowable maximum flow rate with advanced method.
Normally In field cases, gas velocity higher than 1ft/s at the screen is considered as potential fluid velocity which could cause possible completion failure due to screen erosion accompanied by fine particles. One of the gas producing wells in SHWE project operated by Posco-Daewoo at Myanmar offshore, shows moderate mechanical skin damage and heterogeneous flow profile at the screen. Therefore rather than applying general drawdown criteria, calculating gas velocity at screen is recommended. To investigate the velocity profile at well bore, Production Logging was applied to Well-1 at SHWE field. By interpreting the Production logging, a highly biased flow profile was found out and reservoir interval showing highly biased flow would be suspected as of a hotspot zone.
Production logging interpretation results indicate that the flow rate of 500 psig drawdown is much higher than the flow rate correspondent of 1ft/sec velocity at hotspot zone due to highly biased flow profile. In this case, the general drawdown criteria will not guarantee the sustainable maintenance of screen however exposes potential erosion to screen. Therefore, the gas wells suspected to have biased flow profile required to detect any potential hotspot areas and should be operated with advanced criteria to prevent potential sand face completion failure.
Adaptive waveform inversion (AWI) is one of a new breed of full-waveform inversion (FWI) algorithms that seek to mitigate the effects of cycle skipping (Warner & Guasch, 2016). The phenomenon of cycle skipping is inherent to the classical formulation of FWI, owing to the manner in which it tries to minimize the difference between oscillatory signals. AWI avoids this by instead seeking to drive the ratio of the Fourier transform of the same signals to unity. One of the strategies most widely employed by FWI practitioners when trying to overcome cycle skipping, is to introduce progressively the more nonlinear components of the data, referred to as multiscale inversion. Since AWI is insensitive to cycle skipping, we assess here whether this multiscale approach still provides an appropriate strategy for AWI.
Presentation Date: Tuesday, September 26, 2017
Start Time: 3:05 PM
Presentation Type: ORAL
In an effort to reduce project construction and start-up costs, novel and alternative well construction models have been developed and adopted globally. One such approach is to adopt a segregated drilling campaign, the well construction and completions operations can be segregated into two distinct phases. A drilling and casing phase leaving a cased well in a Temporary Abandonment (TA) status, followed by a phase consisting of WBC (wellbore clean-up), completion and stimulation operations resulting in the handover of the well to production to bring hydrocarbon production online. As such this provides an opportunity to reduce surface equipment specification and costs, in comparison to that which is required for drilling activities. A potential solution exists by utilising alternative technology with the capability to perform perforation, multi-zone completion installation, stimulation, WBC operations and well testing, at comparatively lower cost than conventional drilling technology. This paper describes the collaborative development of such technology, and focuses on the definition of the surface equipment requirements and specification phase, pertaining to the typical downhole operations required to be executed during the multi-zone completion installation, stimulation, WBC operations and well testing. Each operation is assessed to give a base required capability, with further operations that are deemed to have a critical effect on the efficiency and duration, identified. A typical anticipated operations program is presented and the study focuses on the first principle requirements of each of the steps. Further operation considerations are presented and discussed for each operational step, forming the basis of discreet specifications per step. Further, the identification of operations not on the critical path that can be performed simultaneously or as an offline activity, have the potential to make high cost impacts. Collaboration between the Yangon based operator and service provider drives a design which provides a technically pragmatic and capable ICU (Intervention and Completion Unit) and as such attracting project cost savings allied to lower support equipment costs. Further, the deployment flexibility of the ICU allows it to perform operations ranging from well construction activities such as well slot preparation, completions and intervention, to well deconstruction activities such as heavy workover, Permanent Abandonment (PA) phases and slot recovery. The ability to perform multi-phase operations whilst mobilized to a platform brings further cost benefits and operational flexibility.
The Ganges Brahmaputra Delta and the associated Bengal Fan is the world’s largest delta/submarine fan complex. The deepwater areas of the Bengal and Rakhine Basins are relatively underexplored frontier areas. In 2003 the large Shwe gas field was discovered in Lower Pliocene turbidite fan sediments with reserve estimates of 6-9 tcf. As additional blocks are licensed, new data will be acquired to evaluate the area including 3D CSEM which is being considered as a complementary exploration method to seismic data.
The controlled-source electromagnetic (CSEM) method has been applied to oil and gas exploration and production for more than 10 years. EM data are used to indicate the presence of hydrocarbons, since hydrocarbon saturated rocks display higher electric resistivity compared to water-filled reservoirs. CSEM is an excellent technique to define the lateral extent of hydrocarbon accumulations and is particularly useful in determining the existence and extent of stratigraphic accumulations.
3D modelling indicates CSEM is sensitive to the Shwe Field reservoirs and can define the lateral extent of the pay zones. 3D CSEM forward modelling has been performed over a range of target sizes within the economic limitations of deepwater drilling, and the modelling shows that CSEM would be sensitive to those targets.
Based on these results, it is concluded that CSEM 3D data will detect the presence of hydrocarbon accumulations and thus, high-grade exploration areas in the greater Bengal Basin.
In this paper we describe how the deepwater reservoir sediments in the Bay of Bengal, dominated by a deepwater turbidite depositional process, is the ideal geologic setting for detecting resistive anomalies related to hydrocarbon accumulations. Turbidites, by nature, are anomalous deposits of sand encased in shale. When saturated with hydrocarbons, they are more resistive than the surrounding shales, allowing them to be detected using the marine controlled source electromagnetic (CSEM) method. CSEM is sensitive to the large Shwe field accumulation on the shelf, offshore Myanmar and is used in this study to illustrate the ranges of detectability in the adjacent deepwater areas (Fig. 1).