To date Trinidad has produced close to three billion barrels of oil from onshore and offshore fields. Formations penetrated range in age from the Lower Cretaceous to the Pleistocene.
Ninety three wells have been drilled to the Cretaceous with varying degrees of success, these wells have identified whether source rock facies are present or absent across the island. Based on well and outcrop data, the Upper Cretaceous interval is shale dominated with occasional turbidite sandstone reservoirs and a siliceous mudstone locally known as "Argilline".
Geochemical research by
Royalty Lease Evaluation (RLE) analysis of oils produced from Upper Cretaceous sandstone and naturally fractured intervals (Specific gravity / API, viscosity, % Sulphur, % of products by distillation) give clues to the origin and history of these oils.
Integration of these results and data can result in identification of areas with potentials unconventional source rock plays.
Cui, Yunjiang (Tianjin Branch of CNOOC Ltd) | Shi, Xinlei (Tianjin Branch of CNOOC Ltd) | Li, Ting (Schlumberger) | Wang, Ruihong (Tianjin Branch of CNOOC Ltd) | Lu, Yunlong (Tianjin Branch of CNOOC Ltd) | Meng, Li (COSL Ltd)
In this case study, we examine permeability estimation in a Middle East carbonate field where oil is mainly produced from the Cretaceous limestone reservoirs. Due to the complex depositional and diagenetic processes, the reservoir rocks exhibit significant heterogeneity in petrophysical properties. In the industry, it is a common practice to estimate permeability with porosity vs. permeability (poroperm) relationships derived from core data. However, in our study field, the semi-log crossplots of core porosity and permeability generally exhibit a wide spread. As a result, the poroperm models determined from these crossplots can make quite inaccurate predictions about permeability.
In sedimentary rocks, variations in pore geometrical attributes define distinct flow units. Within each flow unit, the rocks exhibit similar fluid-flow characteristics and consistent petrophysical properties. Therefore, core samples belonging to the same flow unit generally exhibit better porpoperm correlations than those from the entire well. Based on this principle, we first classify reservoir rocks into a number of facies and then define a poroperm relationship for each facies based on core measurements. The method requires a set of well logs sufficient to classify the reservoir rocks into the distinct facies. In some cases basic logs such as GR, density and neutron porosity will be sufficient, but in other cases additional logs will be required to correctly differentiate the facies. Core measurements are only needed in a key well penetrating the reservoirs under study. The following is the detailed workflow:
Apply a clustering algorithm to well log curves to assign facies to cored intervals.
For core samples in each facies, develop a poroperm relationship based on measured core porosity and permeability in this form: logK = A*phi+B.
Train a self-organizing map with well log patterns associated with each facies at the cored intervals and propagate the facies classification to un-cored intervals using select log curves.
Use the poroperm relationships defined for different facies to calculate a continuous permeability curve for the entire well.
In our study field, wireline triple combo logs and core data were collected in 7 wells. The clustering algorithm identified 5 facies from cored intervals in one key well. The facies classification was then propagated to un-cored intervals in the 7 wells using well logs. Based on core data from the key well, 5 poroperm relationships were established for the 5 facies using regression and continuous permeability curves were calculated from these relationships for the 7 wells. There is an excellent match between predicted and core permeability in all 7 wells. In contrast, a single poroperm relationship that ignores rock facies produces permeability predictions that fail to reflect the full variation in the core measurements in each well. In this report, we show the interpretation results from two wells as validation of the proposed workflow.
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.