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.
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.
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.
Scoping studies using data from three mature fields suggest that simple workflows that use only essential stratigraphic and facies constraints are as good in capturing overall reservoir fluid flow response as complex, highly constrained workflows that use detailed stratigraphic and facies constraints. Thus, considerable time and cost saving may be realized during initial model building and updating if simple, but appropriate, workflows are used.
The reservoirs studied include a Permian-age carbonate reservoir in New Mexico, an Upper Miocene deepwater clastic reservoir in California, and an Eocene-age shallow water clastic reservoir in Venezuela. Two dimensional cross section models of the deepwater clastic reservoir showed that cumulative production and water breakthrough times were essentially the same for models using the two major stratigraphic picks as for models constrained by 12 detailed stratigraphic picks. Three dimensional streamline simulation was used to demonstrate that adding facies and rock type constraints had little impact on recovery factors for a carbonate reservoir scoping project area consisting of 25, 5-spot waterflood patterns. Likewise, a very complex workflow for the shallow water clastic data set from Venezuela constrained by eight facies and 16 detailed stratigraphic picks yielded the same reservoir response as a simple, two facies, and four major stratigraphic picks constrained workflow. These studies suggest that for reservoirs with moderate to high net to gross (>30-40%) or with small differences in the porosity vs. permeability trends of facies/rock types that simple geological modeling workflows are adequate for subsequent fluid flow simulation. Models generated using the shallow water clastic data sets and evaluated using three dimensional streamline simulation showed that varying the semivariogram range parameters by factors between 0.25 and 2 times the data driven range value also had little effect on reservoir response.
An important issue surrounds the impact of up-scaling on fluid flow response. Vertical up-scaling by factors commonly used for full field simulation models has little impact on fluid flow response based on studies of the New Mexico carbonate reservoir and the shallow water clastic reservoir in Venezuela. However, areal up-scaling of models generated using a very fine 50 foot areal grid significantly alters the fluid flow characteristics and warrants additional study.
The information given in this paper is based on archives, interviews with people, etc. and is given to the best of our knowledge. There may be some minor inaccuracies on the dates and on the information given for which we would like to apologize in advance to the readers of this paper and to the providers of the equipment and installations mentioned here.
TOTAL E&P Branch, present today in more than 43 countries and producing 2.6 Mboe/d, has steadily become an important player in the field of Floating (Production) Storage and Offloading facilities, key to several oil and gas field developments. The experience described below is the cumulated experience (upstream) from TOTAL, Petrofina and Elf Aquitaine who successfully merged in 1999 and 2000 to form TOTAL.
As the reader will rapidly notice this experience is extremely rich and diversified and includes many maiden installations as well as technology breakthroughs.
Some of them:
- The Ifrikia (Ashtart field Tunisia 1973) was the first FSO (Floating Storage Unit, converted tanker) permanently moored by a rigid yoke on a CALM buoy, followed in 1978 by the Ifrikia II, the first purpose build FSO barge.
- The Frigg flare (North Sea 1974) was the second Articulated Column. It followed an experimental articulated column installed in 1967 in the Bay of Biscay.
- The first Ready Made Dolphin was installed on Quinfuquena (Angola 1979).
- In the same year the first two turret type CALM buoys were installed on Mayumba (Gabon 1979), then Kole (Cameroon 1979).
- Three CALM type buoys of a new design using self lubricating bushing in lieu of main roller bearing, were ordered for Rospomare (Italy 1981), ABK (U.A.E 1981) and Victoria field (Cameroon 1982).
- The Licorne Pacifique converted tanker on Palanca field (Angola 1984) was the third CALM soft-yoke (the first one was in 1981).
Ashtart, a large fracture enhanced carbonate oil field offshore Tunisia, required a new reservoir model with high prediction confidence to optimize tail end production and to evaluate its remaining upside potential requiring drilling or tertiary recovery methods. Due to the complexity of the field, a synergistic approach was adopted by teaming up the different disciplines and partners.
This approach entailed the creation of a fine scaled structural and petrophysical 3D matrix geomodel. The model was subsequently scaled up and supplemented with observed dynamically acting features such as fault or fracture flow paths and flow barriers. Modeled matrix permeabilities were systematically adjusted to match established well productivities, without arbitrarily changing flow conditions in the vicinity of wells.
Crucial to this process were not only thorough studies of fracture distributions and attributes, but also the integration of all observed fluid dynamic aspects. Pressure transient analyses proved to be a valuable tool, leading to consistent effective permeabilities and the identification of previously unknown lateral and vertical boundaries. Superior history matches following iterative numerical modeling demonstrate the success of this single permeability modeling approach with improved prediction capabilities.
Introduction and Background
Field Outline. The Ashtart field is located approximately80 km offshore in the Gulf of Gabes in water depths of 60 to 70 m. It can be characterized as a structural-stratigraphic closure of shallow-marine nummulitic limestones. The northern and eastern field terminations are defined by reservoir pinchouts. The southwestern flank is marked by a structural dip closure with an initial water/oil contact at2992 m subsea depth. The field is structured by NW-SE oriented horsts and grabens. Large NW-SE striking normal faults separate the central field area from the downthrown southwestern and northeastern parts (Fig. 1).
Reservoir Description. The productive interval comprises up to 85 m of highly heterogeneous nummulitic limestone layers of the El Guéria formation that developed on a northeast-facing carbonate shelf during the Lower Eocene (Ypresian). Reservoir quality is fair to excellent. Mean permeabilities of individual layers range from 9 to 360 md, but can reach up to 3,400 md in the so-called ‘drain', an outstanding flow unit with nearly fieldwide continuity. The presence of fractures enhances the productivities of the wells and is also a crucial factor for the performance of the field. Reservoir and fluid properties are summarized in Table 1 below.
This paper presents a broad critique of the current state of reservoir simulation and its applications with an emphasis on its three key shortcomings: (1) lack of established industry standards for simulation (2) non-uniqueness, and (3) inherent uncertainties in reservoir modeling. Examples are discussed to demonstrate how these factors can and have led to misinterpretation and misuse of simulation results.
The objective of this paper is to initiate a critical self-evaluation by the industry on the use of simulation in reservoir management. During the last decade, reservoir simulation has gained increasing acceptance in this area; yet, its full utilization is stil constrained by several unresolved questions. In fact there is a prevalent skepticism in the industry regarding its role as a consistently reliable reservoir management tool.
Compounding the problem are common misperceptions in the industry regarding the limitations versus capabilities of simulation. Often it is criticized for not producing reliable results which are beyond its capacity (e.g.. ultimate recovery). This is an outcome of its being equated to a deterministic tool, e.g., a chemical process simulator. In reality, it is a probabilistic vehicle much like weather forecasting models. What further amplifies the industry's misgivings regarding simulation is the prevalence of uncontrolled and arbitrary practices prevalence of uncontrolled and arbitrary practices in simulation with too little emphasis on engineering and geologic control.
Simulation can be a very valuable and effective tool. This, however, depends entirely on (a) its acceptance and implementation by the user community as a probabilistic tool with inherent uncertainties and (b) the exercise of stringent engineering and geologic control measures and a structured methodology in its utilization.
This pape is a step in the direction of the two principles noted above. It forms the first leg of principles noted above. It forms the first leg of a three-part series: (I) A Critique of Current Practices, (II) Methodology, and (III) Examples. Practices, (II) Methodology, and (III) Examples. Parts II and III are presented as an addendum to Parts II and III are presented as an addendum to this paper. Part I presents a critique of the current state of simulation and its applications with an emphasis on three key shortcomings: (1) lack of established industry standards for simulation, (2) non-uniqueness, and (3) inherent uncertainties in reservoir modeling.
Part II proposes a general methodology for Part II proposes a general methodology for conducting simulation studies. The methodology allows a systemati (as opposed to an uncontrolled) approach to model selection, construction, validation, and predictions thus reducing the potential for the predictions thus reducing the potential for the commonly noted misuses. Included are steps for engineering and quality control.
Part III presents three examples of Chevron studies Part III presents three examples of Chevron studies where the methodology has been successfully used.
CRITIQUE OF CURRENT PRACTICES
The discussion will consist of four main topics:
1. Overview of literature
2. Current practices
3. Shortcomings of reservoir simulation 4. Misuses
The Effect of Instability on Relative Permeability Curves Obtained by Permeability Curves Obtained by the Dynamic-Displacement Method
Summary. A study was undertaken to investigate how instability would affect the oil/water relative permeability curves obtained by the dy-namic-displacement method. In this method, stable Buckley-Leveret displacement theory is used to calculate relative permeability curves from coreflood data. Thus, to obtain the true relative permeability curves by the dynamic-displacement method, the coreflood must be stable. However, the method frequently has been applied to unstable corefloods. The consequence of this application of the method has not been previously reported.
We compared oil/water relative permeability curves from steady-state and dynamic-displacement experiments at several levels of instability. The results showed that the dynamic-displacement relative permeability curves deviated significantly from the steady-state curves as the degree of instability increased. This observation indicates the need to scale laboratory relative permeability measurements to account for instability. To obtain representative relative permeability curves for numerical modeling of a reservoir, laboratory displacement experiments should be conducted at the same degree of instability as that in the reservoir.
Routine laboratory measurements of oil/water relative permeabilities use the dynamic-displacement method, also referred to as the permeabilities use the dynamic-displacement method, also referred to as the unsteady-state method. In this method, the core is first saturated with oil, which is then displaced with water. Oil and water relative permeabilities are then computed from production and pressure data. permeabilities are then computed from production and pressure data. The technique for computing oil/water relative permeabilities from dynamic-displacement experiments was developed by Welge and Johnson et al. Their derivation of the technique was based on the assumption of a stable Buckley-Leverett displacement. This type of displacement is characterized by the advancement of water as a diffuse front. However, a stable displacement is not always encountered in a dynamic-displacement experiment. It is often necessary to use high-viscosity oils and high displacement rates to obtain a wide saturation range and to eliminate gravity segregation and boundary effects. High displacement rates and high oil/water viscosity ratios, however, tend to make the displacement of oil by water unstable. An unstable displacement is characterized by the lack of a diffuse front of the displacing phase. Instead, the displacing phase advances through the core in the form of well-defined channels known as viscous fingers. Thus instability leads to a breakdown of the assumption of stable Buckley-Leverett displacement. Because this assumption is the principal basis of Welge's and Johnson et al.'s technique for calculating relative permeabilities, it would be of interest to investigate the effect of instability on the computed relative permeabilities.
The objective of this study was to conduct an experimental investigation of the effect of instability on oil/water relative permeabilities, as measured by the dynamic-displacement (unsteady-state) permeabilities, as measured by the dynamic-displacement (unsteady-state) technique. This was accomplished by performing waterflood experiments on unconsolidated sand packs saturated with viscous oils. Different levels of instability, as represented by the Peters-Flock stability number, were achieved by varying displacement rate, sand wettability, and oil viscosity. Oil and water relative permeabilities in each case were computed by Welge's and Johnson et al. permeabilities in each case were computed by Welge's and Johnson et al. technique. A set of control relative permeability data was obtained by the steady-state method for comparison with those obtained from dynamic-displacement data. This paper presents our results, which show that the relative permeability data obtained by the dynamic-displacement method are significantly influenced by the degree of instability of the displacement.
The effect of instability on dynamic-displacement relative permeability measurements has received only limited treatment in the permeability measurements has received only limited treatment in the literature. Displacement rate, viscosity ratio, interfacial tension (IFT), and rock wettability have been recognized as factors influencing displacement stability. Peters and Flocks developed a dimensionless stability number for quantitative prediction of the onset of in-stability in a displacement process. Their stability number for a cylindrical system is given by
(M-1)(v - vc) wd2 Ns = ------------------------------,........................(1) NwKwor sigma
kwor (Pw -Po) g cos sigma vc = ------------------------------,........................(2) w(M-1)
k wor o M = -----------------...................................... (3) k oiw w
The critical value of the stability number was determined to be 13.56. This number and its critical value provide a necessary and sufficient condition for predicting the onset of instability in both oil-wet and water-wet porous media. If in a given cylindrical system the computed value of the stability number exceeds the critical value of 13.56, then the displacement will be unstable. In addition, the magnitude of the stability number provides quantitative information regarding the severity of instability. The higher the stability number, the more severe is the degree of instability. If the stability number for a displacement is less than the critical value, then the displacement will be stable. A detailed discussion on calculating the stability number is presented in the Appendix.
Sufi et al. reported the effects of displacement rate on oil and water relative permeability curves obtained by the dynamic-displacement method. The oil relative permeabilities increased only slightly with increasing rate, while the water relative permeabilities exhibited marked increases. permeabilities exhibited marked increases. SPEDE