Verma, Chandresh (Baker Hughes Integrated Operations) | Rodriguez, Fernando (Baker Hughes Integrated Operations) | Qasin, Qazi Mohammed (Baker Hughes Integrated Operations) | Chaaouri, Aramco Mohsen (Baker Hughes Integrated Operations) | Akel, Sami (Baker Hughes Integrated Operations) | Akiki, Ghassan (Baker Hughes Integrated Operations) | Afolabi, Jonathan (Baker Hughes Integrated Operations)
Energy consumption and demand are steadily increasing. Hydrocarbons have been an important energy provider for several decades, but production from mature oil and gas producers is declining. Great effort is put into improving oil and gas reservoir recovery to meet this rise in energy demand.
In the subject reservoir where the pay zone is a thick, multi-layered limestone, characterized by low-permeability; conventional techniques yield lower than expected production results.
To improve production and the ultimate recovery of the field, extended-reach drilling (ERD) wells with long horizontal multilaterals (Quad and Penta-laterals well types) were drilled to attain maximum reservoir contact (MRC), ranging from 10 to 14 Km. These wells equipped with intelligent completions, enable uniform contribution along the extended horizontal intervals. This contribution is achieved through better flow management of the different sections of reservoir contact, reducing operational drawdown pressures, and delaying gas and water breakthrough. The result is high well potentials, improved long-term performance of sweep and recovery, and increasing net worth of the drilling investment.
This paper presents the lessons learned from hundreds of ERD multilateral wells drilled in the field, including integrated operations, progressive approaches and innovative applications, improved drilling practices on a continuous basis, and the tools and techniques used to drill and complete the wells safely and efficiently.
These efforts achieved a milestone record rate of penetration (ROP) in the Middle East of 5,000 feet per day, and as a direct result contributed to minimizing well delivery time by 35 % and average 25% reduction in well cost in an always challenging drilling environment.
The design approach, job execution and evaluation of drilling performance are presented in this paper; as well as key technical challenges and risks encountered during planning and execution stages and how these were mitigated and overcome for MRC improvement and optimization.
Well construction was challenged to meet the complex multi-lateral with long cantilever sections.
The MRC optimization schemes applied in the field resulted in dramatically reduced days of drilling operations that led to millions of dollars in project savings and the achievement of world class drilling records.
AbstractThis work is focused on exploring the applicability of intelligent methods in assessing porosity and permeability in the context of reservoir characterization. The main motivation underlying our study is that appropriate estimation of reservoir petrophysical parameters such as porosity and/or permeability is a key step for in-situ hydrocarbon reservoir evaluation. We ground our analysis on information on log-depth, caliper, conductivity, sonic logging, natural gamma, density and neutron porosity, water saturation, percentage of shale volume, and type of lithology collected from well loggings in an oil field in the middle-east (a total number of 11 exploratory wells are considered). Data also include porosities and permeabilities evaluated on core samples from the same wells. All these data are embedded in a neural network-based approach which enables us to establish input-output relationships in terms of an optimized number of input variables. Three diverse intelligent techniques are tested. These include: (i) classical artificial neural networks; (ii) artificial neural networks based on principal component analysis (PCA) transformation; and (iii) statistical neural networks based on a bagging approach. Our results suggest that the statistical neural network is most effective for the field setting considered. The application of this neural network with 9 input parameters provides reliable performances in 94% and 81% of the cases, respectively in the training and validation phases, for the estimation of porosity. A trained network with 10 input parameters leads to successfull reproduction of permeability values in 85% and 79.5% of the cases, respectively during training and validation of the network. Results from this study are expected to be transferable to applications involving evaluation of petrophysical properties of a target reservoir in the presence of incomplete well log datasets.
This article describes how to build an integrated model of two fields in order to optimize gas production. It also describes how to find an optimal gas production ratio between the two fields producing into a single collection point, and the basic details and system limitations in carrying out this type of work. The result will be a tool that allows solving optimization tasks.
For the screening of a significant new LNG development a multi-tiered optimization tool was built with the following objectives:
To optimise the sequence of drilling and producing condensate and gas from a field consisting of multiple stacked reservoirs.
To understand that gas requirements could be fulfilled to supply gas to the multiple planned LNG trains
To evaluate if the tool delivered export results of various scenarios for economic screening and future auditing
An integrated model was built consisting of a Controlling Optimization Software (Resolve) to communicate and control the link between a Surface Network Development (GAP), the wells (Prosper), material balance model (MBAL) and a data export and plotting software (Excel). Visual workflow programming in Resolve allowed for simple adjustment of constraints and inputs through all the linked models which can optimise of multiple scenarios.
Parameters that were optimised included:
Sequence of reservoirs to produce
Well phasing over the different reservoirs showing varying condensate gas ratios
Well type, count and respective targeted reservoir
Surface infrastructure including pipelines
The fully integrated model provided the required flexibility for evaluating various scenarios while delivering credible consistent results. Running quick scenarios can help to make decisions for the planning of the surface network and production thus helping to reduce CAPEX. Using central controlling software simplified varying both subsurface and surface constraints for the LNG development. This included seasonality influenced safety margins, the addition of compression as soon as the gas rate potential drops below critical levels and drilling new wells into the optimal reservoir when required to fill the LNG trains.
The Oudna Field is located approximately 80 km. offshore Tunisia (Figure 1). Successful application and optimization of an artificial lift system for this field required a considerable amount of evaluation prior to implementation, in order to take into consideration three specific features of the prospect:
After extensive study of the various artificial lift alternatives available, the decision was made to install the first sub-sea hydraulic jet pump system, capable of producing 25,000 bpd, because it afforded the following advantages:
In this paper the authors explain the need for a long life system, the reasons for selecting jet pumps, the considerations in the design of the jet pump, its installation and operation. The process used for the optimization of the jet pumping system is discussed.
Initial field economics on Oudna was carried out based on a $27 / BBL pricing. With this oil price, under any circumstances the Field was likely to be Marginal. Although confidence existed that the Oudna reservoir modeling was sound this in turn had indicated that both reservoir pressure support and an artificial lift production mechanism would be required to keep oil production levels to that required.
Given that the field is in 270m of water and around 80km from shore then both the Production Handling and Artificial Lift options were going to be limited.
Andersen, Niels (National Space Institute – DTU Space & Polar DTU) | Bekker, Pieter (University of Dundee and Steptoe & Johnson LLP) | Bishopp, David (Galp Energia) | Nassif, Toufic (Sonde Resources Corporation) | Nordentoft-Lauridsen, Sune (National Space Institute & Polar DTU) | van de Poll, Robert (Fugro N.V.)
This paper provides an overview of the history of global maritime boundary issues, mechanisms to resolve boundary disputes, and the economic potential that can be unlocked by coastal States through the exploitation of hydrocarbons trapped in areas currently unavailable for exploration and production operations.
Vast hydrocarbon reserves are tied up in areas, either underlying waters greater than 200 nm offshore or disputed by coastal States. In the former case technology in the form of deepwater drilling has made testing the potential feasible, whilst in the latter case many of the 311 or so areas in dispute are able to be tested and developed using conventional techniques.
Anything that appears to show a sovereign entity ceding control of land or sea to another country inevitably takes on a high profile in the countries concerned, which in the worst case can lead to armed conflict. It is a credit to those States that subscribe to the principles of the United Nations Charter and the United Nations Convention on the Law of the Sea ("UNCLOS") that they have reached agreement on how the economic potential trapped in disputed areas may be divided or shared.
High-profile, high-stakes disputes relating to offshore oil and gas deposits underscore the importance of the modern law of the sea, and international law generally, to the peaceful settlement of boundary disputes affecting the energy industry. Yet boundary disputes form an overlooked area of investment risk management in the energy sector.
This paper will introduce the technical and legal principles behind the solutions reached by States and will highlight some of the areas with the greatest hydrocarbon potential that have yet to be exploited as well as the areas of risk that require mitigation before investors will advance risk capital.
Carbonate reservoirs have petrophysical property distributions largely controlled by a combination of the depositional, diagenetic, and structural (burial/uplift) histories of the reservoir itself and also of the basins that contain them. Carbonates are very prone to diagenetic alteration; porosity and permeability can be strongly affected by the thermal state, fluid-pressure and pore fluid chemistry through their geological history. We use a novel workflow, adapted from basin modelling, to investigate how the burial/uplift history of an offshore carbonate reservoir and its basin, taken as a system, can have controlled the fluid and heat movement within, into and out of the reservoir. The reservoir rock properties and diagenetic history are assessed, as is the local and regional geological evolution for potential contributory factors to the diagenesis. A model of the potential basin system is developed, observed reservoir diagenetic history being added to the normal basin modelling constraints. This model provides good estimates of geometry and property evolution, and of fluid transport, through geological time. Since fluid and heat fluxes are important in the diagenetic evolution of the carbonate pore system, these results are complemented by simulating the movement of heat and brine in the reservoir using finite element-finite volume simulations. These simulations capture the complex geological structures, especially fault-fracture systems, and better represent the flow physics and chemistry that control reservoir diagenesis. Results from these simulations will later be returned to the basin model to improve the calibration of the timing, depth, and rates of diagenetic events.
This new workflow is applied to a Lower Eocene offshore carbonate reservoir with a complex diagenetic history which seems to have a strong basin evolution influence. Importantly this workflow is generic and can be applied to any carbonate reservoir to enhance the link between geological models at the basin scale and reservoir scale models.
Downstream Refineries and Chemical Plants have benefited from real time optimization systems (RTO) for the last 30 years. Downstream RTO is a well established and permanent fixture in many plants - the "way we do things ‘round here!??. Upstream E&P operations have "come to this party?? much more recently and are using RTO more sparingly, even though the economic and HSSE benefits can be very significant.
There are key differences between downstream and upstream. For example, downstream facilities do not deal with sub-surface uncertainties, multiphase flow and isolated/harsh environments; while upstream operations do not usually have to deal with complex chemical processes.
Integrated Oil Companies run upstream and downstream operations and integration of tools/practices across both regimes is often perceived to be of significant value. Hence, the purpose of this paper is to compare and contrast downstream and upstream RTO learnings with a view to identifying and describing:
• similarities in production unit operations e.g. fluid separation, compression etc.;
• key differences between production unit operations;
• cultural differences between operations;
• RTO activities from a technical perspective;
• RTO business benefits and how these might be leveraged and sustained in both directions.
What will emerge from this analysis will be a comparison, highlighting points of commonality and differences, leading to a better understanding of how RTO can be more effectively exploited in the upstream business - the cheapest oil available!
Specifically, it is concluded that RTO in upstream operations is feasible and lucrative, but is relatively rare with sustainability a challenge. Downstream RTO is more common and sustainable, significantly less lucrative, but a "must do?? to compete in a highly competitive, margin constrained business.
The paper presents the integrated reservoir simulation and optimization results of two onshore gas fields. The fields are tied to common separator node, and have the similar gas in place volumes and production potentials. The optimal production plan
for each field is the goal of the simultaneous development planning. Usually, separate field development plane does not consider surface facilities constraints, so overestimates the gas production amount and project lifetime. However, integrated "reservoir-well-pipeline" model allows to optimize the production system and reach the maximum gas production from each field. This paper presents the two gas field production optimization algorithm, also several development strategies with
common production facility constraints are discussed with results. The optimal two-field simultaneous development plan is calculated on integrated computer model taking into account production system constraints.
Cramer, Ron (Shell Global Solutions) | Mehrotra, Shailendra (Shell) | Goh, Keat-Choon (Shell Global Solutions Intl BV) | Steover, Matt (Shell Global Solutions US Inc) | Berendschot, Leo F. (Shell Global Solutions)
Downstream Refineries and Chemical Plants have benefited from real time optimization systems (RTO) for the last 30 years. Downstream RTO is a well established and permanent fixture in many plants - the "way we do things'round here!". Upstream E&P operations have "come to this party" much more recently and are using RTO more sparingly, even though the economic and HSSE benefits can be very significant. There are key differences between downstream and upstream. For example, downstream facilities do not deal with subsurface uncertainties, multiphase flow and isolated/harsh environments; while upstream operations do not usually have to deal with complex chemical processes. Integrated Oil Companies run upstream and downstream operations and integration of tools/practices across both regimes is often perceived to be of significant value. Hence, the purpose of this paper is to compare and contrast downstream and upstream RTO learnings with a view to identifying and describing: - similarities in production unit operations e.g.