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Collaborating Authors
Tanzania
The government of Tanzania has signed a liquefied natural gas (LNG) framework agreement with the UK's Shell and Norway's Equinor that is expected to kick-start construction of a $30- to $40-billion LNG export terminal to commercialize the country's deepwater offshore gas reserves. The deal signed by the three parties on 11 June is foundational to the Tanzanian government's issuance of a Host Government Agreement (HGA) later this year which will outline the project's technical, commercial, and legal terms, according to Bloomberg. Front-end engineering and design (FEED and pre-FEED) will be completed within 3 years of HGA signing, with a final investment decision targeted in 2025. A 4- to 5-year construction period will follow with a first LNG drop planned by 2029–2030. The plant will be built at the East African nation's southern coastal town of Lindi.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > Africa Government > Tanzania Government (0.57)
Abstract Historically, permeability prediction has been a challenge in petrophysical interpretations. As a result, different empirical formulas have been generated in order to assist with permeability prediction. The evolution of Artificial Intelligence (AI) techniques in the industry has led to improvement on permeability prediction from log and core data. The objective of this paper is to determine the reliability of the self-organizing maps (SOM) method in predicting the permeability of the Neocomian sandstone reservoir found in the onshore gas field in South- East Tanzania. Three wells from one natural gas producing field were chosen for this study and one of the wells was used as a blind test well in order to confirm the predictive capacity of the AI technique. The AI technique that was used in the petrophysical interpretation is SOM. The Winland R35 method was used for the creation of eleven (11) hydraulic flow units that were used as calibration in the model of the AI technique. The deterministic petrophysical interpretation was conducted for all wells and the obtained log porosity was stress corrected and used in the multi-line formulae model together with the permeability formulas obtained from the Winland R35 method. The curves obtained from the SOM AI technique were used for calculation and creation of a continuous permeability curve. The performance of the SOM AI technique in predicting permeability of the Neocomian sandstone reservoir was evaluated. The results of predicted permeability from the SOM AI technique was compared against the stress corrected core permeability. The self-organizing maps (SOM) technique produced very good results based on correlation and comparisons between the predicted and stress corrected core permeability. The result showed that the SOM technique has great potential for handling missing curves and was considered to be a reliable method for permeability prediction. Introduction The Songo Songo Gas Field is found in the South-Eastern part of Tanzania, onshore and offshore of the Songo Songo Island in the Rufiji Trough (Figure 1). The Songo Songo Gas Field is located towards the South of the Rufiji Delta. The gas field was discovered in 1974. Natural gas of commercial quantity was encountered in the Cretaceous (Neocomian), shallow to marginal marine sandstones on a fault-block structure. Twelve (12) wells have been drilled to date. The gas Field is currently one of the largest producing gas fields in the East African region.
- Africa > Tanzania > Indian Ocean > Songo Songo Island (0.45)
- Africa > Tanzania > Indian Ocean > Nyuni Island (0.44)
Geological and Field Justification of Yuzhno-Vyintoyskoye Field Development Process Based on Dynamic Marker Monitoring in Horizontal Wells
Dulkarnaev, Marat (LUKOIL West-Siberia LLC, Povkhneftegaz CCI) | Katashov, Alexander (GEOSPLIT LLC) | Belova, Anna (GEOSPLIT LLC) | Husein, Nadir (GEOSPLIT LLC) | Malyavko, Evgeny (GEOSPLIT LLC) | Saprykina, Kseniya (GEOSPLIT LLC) | Upadhye, Vishwajit (GEOSPLIT LLC) | Semenova, Ekaterina (GEOSPLIT LLC)
Summary Effective management of oil and gas field development is impossible without employing an integrated approach to well and reservoir studies, well interference assessment, and analysis of the reservoir pressure maintenance system effectiveness. To make hard-to-recover reserves development effective, the key objective is to develop and substantiate recommendations for stimulating oil recovery and increasing the oil recovery factor. This paper dwells on a new approach to the geological feasibility study of the field development management and inter-well influence evaluation, which involves predictive modelling. Such an approach implies studying the field geological structure, analysing the current recovery status, dynamic quantum tracer-based production profile surveillance in horizontal wells, as well as using Spearman rank correlation analysis to evaluate the performance of the reservoir pressure maintenance system. The subject reservoir is represented by a series of wedge-shaped Neocomian sandstones that are marked by a complex geological structure, lateral continuity, non-uniform distribution of reservoir rocks, and an extensive water-oil zone. At the moment, the subject field is in a production increase cycle (Dulkarnaev et al., 2020). An integrated approach was used in this study to provide an extra rationale to the starting points of the reservoir pressure maintenance system impact at new drilling sites to improve oil recovery and secure sustainable oil production and the reserve development rate under high uncertainty.
- North America > United States (0.29)
- Africa > Tanzania > Indian Ocean > Nyuni Island (0.24)
Geological and Field Feasibility Study of Field Development Management Using Marker-Based Production Profiling Surveillance in Horizontal Wells: The Case Study of the Yuzhno-Vyintoiskoye Field
Dulkarnaev, Marat Rafailevich (Povkhneftegaz Lukoil – West Siberia LLC) | Kotenev, Yuri Alexeyevich (Ufa State Petroleum Technological University) | Sultanov, Shamil Khanifovich (Ufa State Petroleum Technological University) | Chibisov, Alexander Viacheslavovich (Ufa State Petroleum Technological University) | Chudinova, Daria Yurievna (Ufa State Petroleum Technological University) | Katashov, Alexander Yurievich (GeoSplit LLC) | Malyavko, Evgeny Alexandrovich (GeoSplit LLC) | Buyanov, Anton Vitalievich (GeoSplit LLC) | Semyonova, Ekaterina Evgenievna (GeoSplit LLC) | Gorbokonenko, Oksana Alexandrovna (GeoSplit LLC)
In pursuit of efficient oil and gas field development, including hard-to-recover reserves, the key objective is to develop and provide the rationale for oil recovery improvement recommendations. This paper presents the results of the use of the workflow process for optimized field development at two field clusters of the Yuzhno-Vyintoiskoye field using geological and reservoir modelling and dynamic marker-based flow production surveillance in producing horizontal wells. The target reservoir of the Yuzhno-Vyntoiskoye deposit is represented by a series of wedge-shaped Neocomian sandstones. Sand bodies typically have a complex geological structure, lateral continuity and a complex distribution of reservoir rocks. Reservoir beds are characterised by low thickness and permeability. The pay zone of the section is a highly heterogeneous formation, which is manifested through vertical variability of the lithological type of reservoir rocks, lithological substitutions, and the high clay content of reservoirs. The target reservoir of the Yuzhno-Vyintoiskoye field is marked by an extensive water-oil zone with highly variable water saturation. According to paleogeographic data, the reservoir was formed in shallow marine settings. Sand deposits are represented by regressive cyclites that are typical for the progressing coastal shallow water (Dulkarnaev et al., 2020). Currently, the reservoir is in production increase cycle. That is why an integrated approach is used in this work to provide a further rationale and creation of the starting points of the reservoir pressure maintenance system impact at new drilling fields to improve oil recovery and secure sustainable oil production and the reserve development rate under high uncertainty.
Total, CNOOC, and the national oil companies of Uganda and Tanzania have green lighted their $5.1-billion Lake Albert development to tap more than a billion barrels of Ugandan crude and ship it by pipeline across east Africa to Tanzania and export markets beyond. Participants in the signing ceremony Sunday in Entebbe included Uganda's President Yoweri Museveni; Samia Suluhu Hassan, president of Tanzania; Total Chairman and CEO, Patrick Pouyanné; and representatives of China National Offshore Oil Corporation (CNOOC), Uganda National Oil Company (UNOC), and Tanzania Petroleum Development Corporation (TPDC), according to a Total press release. The Lake Albert development encompasses Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. Total operates the Tilenga project, while CNOOC operates the Kingfisher project. Together, these two projects are expected to deliver a combined production of 230,000 B/D at plateau, according to Total.
- Government > Regional Government > Asia Government > China Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT The subsea gas development of Block 2 offshore Tanzania described in this paper is characterized by water depths of up to 2600 meters and tie-back distance to shore of around 100 km. The seabed consists of deep, large scale canyons and steep inclinations towards shore. The reservoir fluids contain very little condensate and the pipeline flow is typically low liquid loading conditions at high water fractions. Extensive studies have been carried out during the last 5 years by the Equinor Tanzania Gas Development Project to verify multiphase flow models for our flow conditions. The key focus of work presented at the MPT 2015 was related to liquid accumulation. However, this work also revealed that frictional pressure drop increases significantly with high water fractions, existing flow models severely under predicts frictional pressure drop at high water fractions, and they are not able to predict the effect of water fraction on the frictional pressure drop little experimental data exist for such conditions (low liquid loading three phase flow at high superficial gas velocities). The work and results related to frictional pressure drop in vertical flow were presented at the MPT 2017, while the key focus of the presentations this time is related to frictional pressure drop in near horizontal flow in low liquid loading at high water fractions. To support model development and model verification experiments have been conducted during 2017 and 2018 in both 8 and 12 inch near horizontal pipes at the Tiller test facility in Norway, while model development and model verification studies have been carried out with both Schlumberger (OLGA) and SINTEF (Ledaflow). This presentation gives an overview of the Tanzania deep water gas development with focus on the flow assurance challenges relates to the subsea to beach concept and the background, motivation for the conducted work, while the experiments (SINTEF)", the model development and verification (Schlumberger and SINTEF) are presented in detail in separate presentations.
- Africa > Tanzania (1.00)
- North America > United States > Texas (0.68)
ABSTRACT A comprehensive three-phase flow campaign, funded by Equinor as part of the Tanzania gas field development project [1] [2] [3], was carried out in the SINTEF Large Scale Loop at Tiller in 2017–2018. The experiments were conducted in a 94 meter long 8" pipe, with 2.5° inclination at 60 bar nominal system pressure, using nitrogen, Exxsol D60 and water with and without glycerol. The motivation for performing this study was to support model development targeted towards reducing prediction uncertainty for high-rate low liquid loading conditions. Specifically, the experiments were conducted at conditions that to a certain extent matched those expected during plateau production for the subsea gas development in Block 2 offshore Tanzania. One of the key concerns was that the presence of oil, water and MEG increases the frictional pressure drop more than current multiphase models predict. The focus of the work was on gas dominated three-phase flows, with low liquid rates (USL=0.0001-0.1 m/s), and mainly high gas rates (USG=4-14 m/s). The effect of the water viscosity was investigated by mixing glycerol (70–74%) with the water, and conducting experiments at different temperatures, yielding water viscosities in the range 14–42 cP. The aim of the experimental campaign was to produce experimental data relevant for modelling two- and three-phase low liquid loading flows at high gas rates. Earlier experiments [4] had revealed that the pressure drop was significantly higher in three-phase flows compared to two-phase flows, and the current experiments were conducted to investigate this phenomenon more thoroughly. In this paper we provide an overview of the experimental campaign, and we show some of the key results. Some of the main findings from the experiments were: The pressure drop depends significantly on the water cut. In general, the pressure drop increases with water cut, reaching a maximum value at around WC=80%, after which the pressure drop decreases again. For three-phase experiments with tap water, the maximum pressure drop was typically 20–40% higher than for two-phase gas-oil, while with the water/glycerol mixture, the maximum pressure drop could be up to 80–100% higher than for the gas-oil system. For high water cuts, the frictional pressure drop increases with increasing water viscosity, while for low water cuts, the frictional pressure drop is independent of the water properties.
- North America > United States (0.68)
- Africa > Tanzania (0.46)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
ABSTRACT In this paper we present a detailed analysis of large scale experimental data from the SINTEF Multiphase Laboratory on high-rate low liquid loading flows. The experimental work [1] was funded by Equinor as part of the Tanzania gas field development project [2] [3] [4], and SINTEF was granted access to use the data for improving the accuracy of the pressure drop predictions in LedaFlow. The experimental results showed that a key element for predicting high-rate low liquid loading flows accurately is to account for the droplets that deposit on the walls in the gas zone, creating a wall film. This wall film can have a profound effect on the hydraulic roughness experienced by the gas, and subsequently the frictional pressure drop. Furthermore, the data showed that this effect was particularly important for high liquid viscosities and in three-phase flows, and simulations showed that LedaFlow had a clear tendency to under-predict the pressure drop in such scenarios. To improve this situation, we used the data to derive a model for predicting this complex phenomenon. This paper summarizes the main parts of the data analysis and the development of the wall film model. We show that by introducing this new model into LedaFlow, we were able to significantly improve the agreement with the measurements. 1 INTRODUCTION Low liquid loading generally refers to flow conditions where the superficial liquid velocity is small compared to the superficial gas velocity. This is a typical scenario for wet gas lines, where the reservoir produces mostly gas, but where changes in the pressure and temperature along the pipe causes condensation of water and hydrocarbons, so that the liquid rate increases with the distance from the well.
- Europe (0.68)
- North America > United States (0.28)
- Africa > Tanzania (0.25)
- Overview > Innovation (0.35)
- Research Report > New Finding (0.34)
- Production and Well Operations > Artificial Lift Systems > Gas well deliquification (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (0.90)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.89)
- Well Drilling > Drilling Operations (0.87)
Abstract Significant gas discoveries have been made in deep waters off the coast of Tanzania this decade. Operator Equinor (previously Statoil) with co-venturer ExxonMobil have drilled 15 exploration and appraisal wells in Block 2 about 100 km from the shore in the southern part of the country. The objective is to develop gas resources for a large LNG project. This paper focuses on the various discoveries made and the subsurface understanding gained over the last years. The reservoirs are all deposited as turbiditic sandstones in different geologic periods (Cretaceous to Miocene), and have a long and complicated geological history. Heavy tectonic activity including development of pop-up structures along a major strike-slip system, has impacted the depositional environment. Since some of the reservoirs have significant internal faulting, methods to analyze fault transmissibility have been key. The seismic quality is generally good, and in certain reservoirs even good enough to directly use seismic inversion dataset to map the structure more accurately. The exploration and subsurface teams worked together in improving the development concept and minimizing risk. The youngest reservoir (Miocene) has excellent reservoir properties but special challenges with shallow overburden with top reservoir 400-500 m below the seafloor. Several studies have been completed to ensure that production wells can be safely drilled and produced during reservoir depletion, and that the reservoir seal has full integrity. In deep water oil and gas developments it is important to demonstrate large, continuous flow units with good flow properties before investment decisions. For the Block 2 gas reservoirs understanding the aquifer strength is important for designing wells so that water production can be avoided. Detailed aquifer modeling has been made for all the main reservoirs. Modelling showed risk of water production for one of the reservoirs; however, it is expected that this risk can be mitigated by placing the planned producers high on the structure. Deep seabed canyons are present in the area and these give important constraints on drilling locations and subsea layout including the major gas pipeline to shore. The field development is planned as a subsea-to-shore development without any fixed installations offshore. To predict the dynamic performance of such a huge and complex production system, extensive flow assurance studies have been completed.
- Africa > Tanzania (1.00)
- North America > United States > Texas (0.46)
- Phanerozoic > Mesozoic > Cretaceous (0.67)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.45)
- Geology > Sedimentary Geology (1.00)
- Geology > Structural Geology (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.49)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.68)
- Geophysics > Seismic Surveying > Seismic Processing (0.68)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.48)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > P’nyang Field (0.99)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Elk-Antelope Field (0.99)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Angore Field (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)