Matthew, Free (Arup) | Esad, Porovic (Arup) | Jason, Manning (Arup) | Yannis, Fourniadis (Arup) | Richard, Lagesse (Arup) | Charlene, Ting (Arup) | Grace, Campbell (Arup) | Areti, Koskosidi (Arup) | Andrew, Farrant (BGS) | Ricky, Terrington (BGS) | Gareth, Carter (BGS) | Tarek, Omar (ADMA-OPCO)
This paper presents a new purpose-built digital interface for obtaining location-specific geological and geotechnical ground conditions for four oil and natural gas fields offshore of Abu Dhabi in the UAE. The geological model was developed using the software package GSI3D which was applied to an offshore study area for the first time. Statistically derived geotechnical parameters were used to apply a probabilistic approach for the design basis of geotechnical elements for offshore structures. In addition, geostatistical methods were applied in the treatment of geological uncertainty in the model. The model also includes a detailed review of local and regional natural hazards, including seismic, tsunami and submarine geohazards, with the potential to affect existing and proposed offshore infrastructure.
The tool comprises a fully interactive 3D geological and geotechnical ground model for each oil and gas field based on a geodatabase containing nearly 60 years of ground investigation data. The interface is operated through ESRI ArcMap but the geodatabase can be integrated into any online or offline GIS- based platform. Application of the tool enables effective decision making on key oil and gas development issues related to the siting of new exploration and development platforms and related infrastructure. The costs associated with offshore ground investigations are significant and mobilisation of works are heavily constrained by access, health, safety and environmental requirements. This digital tool will allow these works to be optimised at the advanced stages of planning, saving on time, cost and significantly reducing health, safety and environmental risks.
Hatvik, Mahanaz (TechnipFMC) | Nørgård, Jens Petter (Lundin Norway) | Berg, Kjartan (Lundin Norway) | Vannes, Knut (TechnipFMC) | Irmann-Jacobsen, Tine Bauck (TechnipFMC) | Cantero, Alberto Diaz (Rock Flow Dynamics)
The world's average oil recovery factor is estimated to be 35%. Increased oil and gas recovery will depend on the availability and utilization of appropriate technology as well as efficient reservoir management and economic strategies. This creates the need for efficiently scanning and evaluating various field architectures during the field development phase, with respect to installed cost, operability and hydrocarbon recovery. A major step towards achieving this improvement is to couple the reservoir performance with the production network.
The objective of this paper is to describe an efficient methodology for coupling one or several dynamic reservoir models with the production network model. This enables effective comparison between different field development concepts including various applications of subsea processing.
To investigate this integrated approach, a real case study has been performed on the Alta and Gotha discoveries operated by Lundin in the Barents Sea.
Well placement within thin and discontinuous reservoirs continues to prove challenging in present-day field development. Some geological objectives require draining accumulations within discontinuous reservoir fairways with thin true vertical depth (TVD) thickness (<7 m). The ability to geosteer within these complex systems using modern azimuthal tools has provided some solutions; however, there are multiple other elements contributing to successfully landing a drain with such reservoir scenarios.
Turbidite channels are common within the offshore Niger Delta systems and in many other basins. The Niger Delta Basin is predominately a clastic system, and the reservoir targets in this fairway are a mix of structural and stratigraphic traps made up of sand and shales deposited during the Early Pliocene period. These systems are generally described as turbidite channellevee complexes.
This paper discusses a case study using two recently drilled wells to analyze the technique/approach used for a successful and safe well placement operation. This approach involves two parts: the use of technology (geosteering tools) and the role of communication for a successful well placement operation. The primary tool used was azimuthal deep resistivity, which uses resistivity contrast within beds to help geosteer and stay within reservoir bodies, hence optimizing well placement. Guided by azimuthal resistivity imaging, it was possible to determine the well direction relative to the beddings using oriented binned data and resultant images.
The communication aspect involved prejob, on-the-job, and post-job elements that contributed extensively to successful operations. A closed-loop approach to decision making was implemented whereby azimuthal resistivity data (and geosignal ratio curves) were measured and transmitted in real time, then analyzed by a team in the office collaboration room who transmitted information back to the rigsite for implementation. This paper also documents the uncertainties associated with the measurements and the processes available to mitigate them as well as lessons learned.
Two wells were placed within undrilled fairways with reservoir and depth uncertainty. With the help of pilot holes 6 and 7-m TVD thick, hydrocarbon sands were discovered. Drains of 400 and 700 m were placed within these fairways, and each well exhibited good productivity. Interpretation of geosignals measured while drilling along with real-time follow-up on the seismic and knowledge of the geological setting were instrumental in the successful placement of these producing wells. The decision-making and analysis process was optimized, thereby achieving operational excellence (health, safety, and environment and timing) and cost savings. The most significant element of these operations is communication. The ability to analyze information and implement decisions rapidly involved all essential disciplines from service company personnel to drilling and completions to geosciences.
Advancements made in geosteering technology and lessons learned from this case study can be applied to future well planning for geological targets originally assumed to be difficult, impossible, or too thin to be successfully drilled to increase field productivity.
Petrobras has been carrying out intensive exploratory efforts in the Campos Basin ring fences, seeking to selectively drill exploratory opportunities close to the already existing production infrastructure. This strategy aims at contributing to the expansion or maintenance of the production curves related to the existing projects in these areas. The Exploration, Reservoir and Production teams work in an integrated way, in order to optimize each project through the extensive application of the existing data and information, taking advantage of the available infrastructure and resources. This approach leads to better economic estimates for the remaining exploration opportunities, boosting investments and further production. Excellent exploration results have been obtained by applying this integrated approach, including recent discoveries in the Campos Basin Pre-Salt reservoirs in the Marlim (Brava), Marlim Sul (Poraquê-Alto) and Albacora (Forno) ring fences, adding significant volumes to the ongoing revitalization projects. Surrounding the ring fence areas in the Campos Basin, new play concepts and technologies have been also applied, resulting in significant discoveries, such as Tartaruga Verde and Tartaruga Mestiça oilfields, both with expected first oil production in 2018.
Gas hydrate has been found both in the permafrost and deep ocean in China. However, due to easier access, much lower well cost and proximity to existing gas pipelines, gas hydrate in the permafrost is more attractive for commercial development. In this paper we examine the published data on gas hydrate exploration in various Chinese permafrosts, identify the key technical challenges and suggest directions for future study.
Our study has identified Qilian Mountain Permafrost, Mohe Basin and Qinghai-Tibetan Plateau as the three permafrosts with highest potential for gas hydrate development. Of the three, only Qilian has confirmed occurrence of gas hydrate by coring. From the perspective of field operations, Qilian ranks highest in potential for development due to its proven hydrate occurrence, thickness of hydrate bearing layer and proximity to existing gas pipelines. Mohe ranks second due to its benign operating conditions. However, it lacks existing gas pipelines. Qinghai-Tibetan Plateau ranks third due to its high elevation which limits access and lack of oilfield infrastructure.
We found that the key subsurface uncertainty is the gas hydrate saturation. There is little information on it for all three permafrosts. Other subsurface uncertainties include the thickness of the permafrost, geothermal gradient beneath the permafrost, porosity, gas hydrate composition and permeability of the hydrate-bearing layer. Future research needs to determine these reservoir properties accurately.
Examination of core samples and logs from Qilian shows that gas hydrate distribution is discontinuous both vertically and areally. Therefore, a better way to quantify the uneven hydrate distribution in the reservoir is needed for reservoir engineering calculations.
Current estimates of well production rate by reservoir simulation are sub-commerical and probably due to the assumption of pure methane hydrate which limits the thickness of the gas hydrate stability zone. Also, the assumption of using horizontal wells for hydrate production may be optimistic due to shallow depths and the discontinuous nature of hydrate distribution. Consequently, new recovery methods besides depressurization and thermal stimulation will be needed to increase the well production rate.
Furthermore, we have identified a number of similarities in production engineering aspects of gas production from hydrate and coalbed methane (CBM) wells. Common challenges include reservoir depressurization by water production, solids production, need for artificial lift and difficulty in drilling long horizontal wells in shallow reservoirs. Therefore, some best practices from CBM production, such as pad drilling, artificial lift and water treatment methods, may be usable for gas hydrate production.
With two different reservoirs – Miocene and Albian; a development combining brownfield and greenfield; two production platforms – a Floating Production Unit (FPU) and a Tension Leg Platform (TLP); and the collapse of the oil price during the project execution phase … Moho Nord operated by Total E&P Congo is a highly complex project. The objective of this paper is to show how Total managed to ensure the success of the project phase.
The development scheme of Moho Nord is above all an optimal response to the constraints imposed by the different reservoirs. Then, Total had to efficiently supervise this complex project during the industry downturn, while maximizing the local content in Congo, drawing on the best available technologies to reduce the environmental impact of the new installations, and developing innovations notably to be able to simultaneously drill, intervene and produce the complex Albian reservoirs.
Total successfully completed this large and complex project, including the first TLP for the Group in Africa. Production started in March 2017 less than four years after the Final Investment Decision (FID). Three floating units are involved: the already existing FPU Alima and the new-build FPU Likouf with a typical subsea production layout, and the TLP with surface trees. Production is sent onshore to the existing terminal at Djeno.
To meet the challenge of a dual development comprising brownfield and greenfield sites, Total created an integrated muti-discipline team to work on the upgrade of FPU Alima and its subsea network, modifications to the Djeno terminal, and the construction of the new FPU and TLP units. Packages for Umbilicals, Flowlines Risers (UFR), Subsea Production System (SPS), Geosciences, Drilling, and Support services were shared across the whole development.
The main contracts were signed in 2013 before the oil price collapse and Total had to rely on the expertise and creativity of its teams and contractors to manage the project through difficult times, without compromising success and safety.
With the Moho Nord project Total has demonstrated its capacity to manage a large, complex brownfield and greenfield project to time and budget even in a difficult economic climate.
In this study, pore pressure prediction for a HPHT exploration well was conducted using both convention 1D modeling method and 3D basin modeling approach. Due to the considerable challenges encountered in three nearby fields (narrow mud weight windows, over pressure up to 17.0-17.8 ppg, and temperature as high as 185 °C at projected well TD), 3D basin modeling was considered as an alternative approach to help reduce the uncertainty due to lack of constraining data for conventional 1D modeling.
Both Eaton and Bowers methods were used to generate 1D models of the pore pressure profile from seismic interval velocity. Calibration of the models was based on offset wells of the three nearby fields. On the other hand, 3D basin modeling approach was used to model all three fields together. Detailed lithology was defined for each layer of the basin. By carefully calibrating the relationship of porosity-effective stress, porosity-permeability, and varying sealing capacities of the faults, a good match was obtained between the 3D basin pore pressure distribution and pressure data measurements from offset wells of all three nearby fields. After the calibration process, pore pressure profile of the HPHT exploration well was extracted along the proposed drilling well path.
Modeling a basin consists of reconstructing the deposition history of the entire sedimentary sequences from geological, geophysical, and geochemical data. It allows establishment of paleo water depths and heat flows in burial sediments to understand the hydrocarbon generation, migration, and accumulation processes during the geological history of a basin. The accurate definition for porosity-effective stress and porosity-permeability relationship of layers of source rock, reservoir, and seal will generate reliable pressure regimes in the basin. Extraction of 1D pore pressure profiles showed an excellent match with measured pressure in offset wells.
In addition to providing pore pressure prediction to optimize drilling plans, 3D basin modeling could deliver rock properties data for further wellbore stability studies in exploration areas. This is valuable for HPHT offshore drilling to help reduce the possibility and severity of drilling issues such as kicks, losses, and wellbore collapse.
Khair, Abul (PETRONAS Research Sdn Bhd) | Zakaria, H. (PETRONAS Research Sdn Bhd) | Ali, A. (PETRONAS Research Sdn Bhd) | R., Y. Som (PETRONAS Research Sdn Bhd) | Hady, H. (PETRONAS Research Sdn Bhd) | Baharuddin, S. (PETRONAS Research Sdn Bhd) | Goodman, A. (PETRONAS Research Sdn Bhd)
Big attention was directed towards the deepwater fields offshore Sabah area after the discovery of commercial hydrocarbons Sabah in 2002. Hundreds of wells were drilled in up-faulted structural traps within North East trending thrust ridges which some of it are dry. The interpretation of these reservoirs was established as a series of four turbidite fans from Upper Miocene to Pleistocene. Yet, no correlation was found between the same fan in different locations with regards to geometry, thickness and mineral composition. This research studied over 50,000 sqkm of 3D seismic surveys, over 100 wells with different sets of logs including image logs, cores from two wells and bathymetric images. Normal seismic structural interpretation was conducted and seismic attribute of the turbidite fans were analysed. Seabed morphology was examined using bathymetry surveys and 3D seismic. The deepwater sediments type and depositional environment were investigated using core and log data.
The geometry of the oil prone sand reservoir bodies and heterolithic sand bodies within the deepwater fields was found to be of three types: North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah, North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1, Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah,
North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1,
Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
This new understanding of the source and sediment supply of the deepwater fields Northwest (NW) Sabah explains the geometry, distribution and lack of correlation within the Miocene sediments. Thus, this study will direct the future exploration in the deepwater reservoirs.
Dinh, Chuc Nguyen (PetroVietnam Exploration Production Corporation) | Nhu, Huy Tran (PetroVietnam Exploration Production Corporation) | Thanh, Ha Mai (PetroVietnam Exploration Production Corporation) | Viet, Bach Hoang (PetroVietnam Exploration Production Corporation) | Van, Xuan Tran (Ho Chi Minh City University of Technology, VNU-HCMC) | Thanh, Tan Mai (Ha Noi University of Mining and Geology)
Cuu Long basin is a Cenozoic rift basin located in the southeastern shelf of S.R. Vietnam, containing vast potential oil and gas resources. The basin was impacted by three main tectonic periods of pre-rift, syn-rift and post-rift tectonism. Major petroleum plays in Cuu Long basin are the Pre-Cenozoic fractured basement, Oligocene and lower Miocene sandstone reservoirs. Upper Oligocene sediments were deposited during late syn-rift phase of Cuu Long basin. The reservoirs in these strata (Oligocene C and D) were previously discovered in the center, southwestern and southeastern margins of Cuu Long basin with limited total reserves, up to 5%, of Cuu Long basin's discovered reserves. Recent exploration and appraisal results of St, Tg, Rg, Ct etc. show a greater potential of upper Oligocene reservoirs with a greater variety of trap types in many areas of Cuu Long basin than that of previous assessments. Therefore, additional studies and assessments of recently discovered trap types need to be carried out for the Cuu Long basin exploration and appraisal program. This article discusses the assessments of upper Oligocene trap types and identifications of several trap mechanisms utilizing the integration of exploration methods. The research results permit better understanding of the trapping mechanisms and possible distributions of various trap types in the upper Oligocene strata of the Cuu Long basin, thus leading to better planning of exploration/appraisal strategies in the basin.
Abdullah, Siti Aishah (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited) | Barker, Steven M. (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited) | Jong, John (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited) | Watanabe, Yoshiaki (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited) | Bakar, Dayang Aimi Nuraini Awang (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited) | Khamis, Mohd. Asraf (JX Nippon Oil & Gas Exploration Deepwater Sabah Limited)
This study presents a play-based evaluation of the southern part of the deepwater NW Sabah fold-thrust belt, a key exploration area in Malaysia. The key objective was adding value to the existing database through an integrated approach. This goal was achieved by analysing four critical geological risk elements: reservoir presence, structural evolution, top seal integrity, and timing of hydrocarbon charge and migration, to identify prospective areas for future exploration by integrating all available geological, geophysical and geochemical information into a consistent petroleum system framework. Using the basin-play-prospect maturation workflow, data spanning the geophysical domain (with inputs such as seismic evaluation, structural mapping and attribute analysis) to the geological realm (such as well correlations, fairway mapping, sedimentological studies, biostratigraphic investigations and source rock maturation modelling), are combined with structural kinematic evolution to generate detailed play-based element maps. The application of the tried and tested play-based evaluation methodology from basin evaluation through to prospect maturation has been carried out. This has led to a comprehensive play element analysis yielding a composite risk segment map within a consistent petroleum system framework. In addition, the study has provided sensible explanations for dry hole analysis, an important reality check, but most importantly it has generated a fresh insight into the overall prospectivity of the study area. This enhanced multi-discipline analysis is beneficial for reducing exploration risk for future expenditure in a time of depressed oil prices that calls for a more innovative approach for deepwater exploration. In summary, integration of available data and the application of new in-house ideas and solid geoscientific knowledge has added value through the generation of increased prospectivity, however for further ground-truthing the real litmus test has to come from future drilling.