Mallick, Tanmay (Shell India Markets Private Limited) | Garg, Ashutosh (Shell India Markets Private Limited) | Choudhary, Manish (Shell India Markets Private Limited) | Nair, Saritha (Shell India Markets Private Limited) | Pal, Sabyasachi (Shell India Markets Private Limited) | Jana, Debadrita (Shell India Markets Private Limited) | Singh, Abhinav (Shell India Markets Private Limited) | Goudswaard, Jeroen (Shell India Markets Private Limited) | Faulkner, Andrew (Shell India Markets Private Limited) | Salakhetdinov, Ravil (Shell India Markets Private Limited)
A new seismic and quantitative reinterpretation was carried out for a brownfield in Western Desert, Egypt to improve depth predictability, de-risk appraisal well locations and to better understand producer-injector connectivity.
The study field is located in the Western Desert, Onshore Egypt and comprises of Upper Cretaceous tidal channel systems across four key reservoir levels where sand thicknesses range from 2 to 15 m. The field was discovered in 1993 but development drilling only commenced in 2008. The last integrated field study was performed in 2012. The analysis of wells drilled post-2012 indicated that there is a considerable depth difference along the flanks of the structure between seismic predicted depths and actual well tops (>50 m). The fault interpretation also required a re-look so as to reduce the lateral uncertainty of the main boundary fault and explain the lack of injection response in some areas of the field. This necessitated an update of seismic interpretation, static and dynamic models. A new interpretation could help identify attic volume upsides and help mature new appraisal and producer-injector locations. Further work was also proposed to test the feasibility of using seismic inversion for facies discrimination.
The available Pre-Stack Depth Migration (PreSDM) data was re-interpreted as part of the project. The fault interpretations were quality checked using Semblance/Dip maps, sand box models and wherever possible, were tied to the fault cuts seen in previously drilled wells. The time horizon correlation and seismic polarity were verified and were also cross-checked with the P-Impedance volume before being used in the static modelling workflow. The PreSDM Interval velocity model was used for depth conversion, where an anisotropy correction was applied to tie the wells. Vok and Polynomial methods were also applied, which in turn were used to derive depth uncertainty estimates. The update in the main bounding fault interpretation generated new appraisal locations in the deeper levels. The new interpretation was tested against the results from the latest drilling campaign in the field, and nine out of ten wells were within the one standard deviation uncertainty range.
Simultaneous inversion of the seismic data was also carried out as part of the project using the acoustic, shear and density data from 6 wells over the field. The inverted P-Impedance and S-Impedance were converted to Net to Gross (NtG), and were checked against the remaining 24 wells, which helped in validating the property cubes.
Forward wedge modelling suggested that individual sands of less than 15 m thickness would not be resolved from seismic due to seismic bandwidth limitations. Still, a review of inversion data together with geological insights and dynamic data helped to identify the high NtG areas across the reservoirs.
The integrated interpretation of inverted volumes with well and production data resulted in new insights into the field and helped to mature new appraisal and development well locations.
Khural, Harsimran (Shell India Markets Pvt. Ltd.) | Rai, Udai Bhan (Shell India Markets Pvt. Ltd.) | Kumar, Ram (Shell India Markets Pvt. Ltd.) | Marpaung, Billman (Sakhalin Energy) | Faulkner, Andrew (Shell India Markets Pvt. Ltd.) | Kumar, Rajan (Shell India Markets Pvt. Ltd.)
The use of smart completion with downhole fluid control through Inflow Control Valves (ICVs) has been extensively described in the literature for balancing the water injection profile and improving the sweep efficiency in commingled water injection. This paper describes the limitations of such a system in ensuring zonal distribution of water in stacked, highly heterogeneous reservoir systems.
Voidage replacement and pressure maintenance requirements necessitate waterflood under fracturing conditions in the four stacked reservoirs (Zone 1 to Zone 4) in Piltun field, offshore Sakhalin Island, Russia. These reservoirs are heterogeneous with differences in their permeability and fracture gradient. Consequently, smart injectors with four ICVs were planned to maintain the desired injection allocation in these reservoirs. The initial injectivity of these wells was extremely low with all of the injected water going to the deepest zone (Zone 4). An expensive pump upgrade improved the overall injectivity, with drastic changes in the distribution of the injected water amongst the reservoir layers. Contrary to performance prior to pump upgrade, the shallowest zone (Zone 1) emerged as the dominant receiver of injected water. Overall, the zonal distribution of water remained a problem with little success in injecting water in the remaining two zones (Zone 2 and Zone 3). Very limited improvement in the water distribution was obtained by manipulating the ICV valves.
Sector modeling was taken up for the injection wells to understand the injection behavior. Modelling results show that after the pump upgrade, fracturing was initially achieved in all zones, although sustained fracture opening and propagation was only possible in Zone 1, the reservoir with better flow properties and reasonably low fracture gradient. The other zones gradually reverted back to injection under matrix conditions with time. The additional pressure drop created by the flow control device is not sufficient to choke back the major zones and achieve sustained fracture growth and water injection in the minor zones in Piltun field. The results demonstrate that the use of intelligent completion for waterflood conformance can be limited by large stress and permeability contrast.
A field in South Oman discovered in 1978 is an over-pressured sour oil reservoir. Since first oil began in 1982, the field will has gone through three stages of development during its life. These can be summarized as follows; pressure depletion, pressure maintenance with sour separator gas plus sweet make-up re-injection, pressure maintenance with sour separator gas plus sour makeup gas injection from other fields
The field produces from the A4C unit of the Ara Group intra salt carbonates. A carbonate reservoir totally encased in salt. No water has been produced to-date from this reservoir. The reservoir oil column is overlain by a gas cap and the reservoir fluid exhibits a strong compositional gradient which impacts the degree of richness required for a sour miscible gas. Development drilling and the construction of facilities proceeded with all well tubulars and facilities constructed out of carbon steel. Operation of the plant and wells occurs with high regard to the risks of sour, high pressure service, and with no integrity or corrosion has been observed to-date.
The field produced under depletion starting in 1982 through oil and gas cap expansion mechanism. The field was shut-in in 1986 awaiting gas injection. In 1993, sour separator gas combined with sweet make-up gas was re-injected as a pressure maintenance project to keep the reservoir pressure from dropping further. Upon expansion of the production station to take production from other nearby sour oil fields, more sour gas was added to the gas injection stream in 2004. Plans are developing to change the composition of the injection gas stream to achieve higher H2S levels so that the injected gas will become miscible with the A4C oil. This is designed to further increase oil recovery.
The purpose of this paper is to present the development history of this sour oil reservoir along with presenting the development approach that has been taken for injecting sour gas to increase oil recovery in this remote South Oman reservoir.
This reference is for an abstract only. A full paper was not submitted for this conference.
Floating LNG (FLNG) has captured the imagination of engineers and LNG business developers ever since it was first considered over a decade ago. The concept is simple, but attractive: "Let's put the LNG facilities directly over the offshore gas resource rather than processing and piping the gas long distances to shore". FLNG has huge potential to extend the portfolio of traditional LNG schemes necessary to meet the energy challenge of the 21st Century. Whilst technological and commercial challenges may have prevented FLNG succeeding to date, as evidenced by the fact that there are no FLNG facilities currently in operation; and whilst today's dynamic business environment, technological advancements, maturing 'easy gas' developments, heightened environmental scrutiny and overheated construction market have delayed FIDs for LNG projects, this same combination of forces and trends have led to the energy industry's renewed interest in FLNG.
Shell will share its perspectives on FLNG - reflecting on the learnings of past studies as well as looking forward to its plans over the next decade, including the expectation that one or more of its FLNG solutions will be in operation globally. The current technical concept with some of its key technical challenges, and the inherent safety approach applied throughout the design will be described. The process configuration of the topsides, the design of the substructure, the environmental characteristics, and the mooring system will also be covered.
Al-Rawahi, Zuwena (PDO) | Faulkner, Andrew (Petroleum Development Oman) | Matvienko, Alexander (Petroleum Development Oman) | Al-Mayahi, Najma Mohamed (Petroleum Development Oman) | Boersma, Diederik Michiel (Petroleum Development Oman LLC)
This reference is for an abstract only. A full paper was not submitted for this conference.
Pre-Cambrian carbonate reservoirs occur at depths between 3-6 km in the subsurface of South Oman. These reservoirs are typically over-pressured, encased in and sealed effectively by thick Ara evaporites and contain sour oil. They have been a focus for exploration since the late 1950s. The discovery in 1976 of commercial oil in these "stringers?? opened up the Ara play and PDO has since then been actively exploring for these deep oil reservoirs in the South Oman Salt Basin.
Compared to the more conventional reservoirs in Oman, the Ara stringers are complex and pose challenges both in the sub-surface and to surface facilities design, which typically results in a long lag time between discovery and well hook-up. Following the discovery of the Budour NE field in 2005, we challenged to dramatically reduce the time to develop these reservoirs. Thirty five years on, with surface facilities in place and with several producing fields nearby, it was possible to accelerate the appraisal of the discovery and achieve early oil production.
This was achieved through the formation of an integrated exploration and development team that could capitalise on existing infrastructure and local expertise, and was able to deal effectively with appraisal uncertainties. The team worked on the definition, quantification and planning of the field development. This resulted in additional volumes, an acceleration of appraisal drilling, and the early hook-up of the discovery for extended flow testing in 2007, i.e. 18 months after discovery. The latter is a record within PDO for a deep oil discovery. This hydrocarbon maturation exercise will deliver fast reserves, early initial production and an accelerated full field development.