Today, mature fields are a major interest for many oil companies since their un-recovered potentials are expected to help satisfy the worlds growing oil demand. However, while operating in such fields companies face new challenges.
As such, many mature fields show under-hydrostatic reservoir pressure due to depletion, which might lead to no returns to surface during workover operations. No returns to surface make it impossible to recognize any losses as an indicator for potential formation damages or gains as an indicator for a potential kick.
The crucial question is therefore how to recognize losses or gains in real time without returns to surface during workover operations?
Knowing the depth of the fluid level in the well at any point in time would allow recognizing losses and gains, simply by monitoring all the changes of the fluid level in the well.
This paper presents a newly developed measurement approach using a specially designed echometer that allows monitoring the fluid level in the well without returns to surface during workover operations automatically in real time, which is a fundamentally new application for an echometer.
All the technical requirements that were identified to be critical for this measurement approach are highlighted in the paper. Further the paper lines out all the associated technical challenges that were faced while implementing this measurement approach. Finally, reliability and functionality of the measurement approach were proven in a series of field tests under various operational conditions.
Concession 97 in the Sirte basin of Libya is subdivided into three different exploitation areas (figure 1). The operator, Wintershall, developed discoveries in each area in 1988, 1990 and 1995 respectively. The producing reservoirs are in the challenging Sarir and Lidam horizons. The Sarir reservoirs are stratified sandstones with medium to very low permeability. The Lidam formation, consisting of a lower limestone and an upper dolomite, has limited net pay. While reservoir rock properties in both Sarir and Lidam reservoirs are of rather poor quality, the oil properties are very favourable.
Ongoing appraisal and the application of advanced exploration methods in recent years resulted in the discovery of additional fields and extensions. Substantial additional volumes have been appraised. However, primary recovery factors are expected to be relatively low.
Recent discoveries and the optimisation of the existing fields led to the completion of an integrated re-development of the entire concession. Three decentralized gas-oil separation plants were recently replaced by a central unit including gas utilization. A key challenge of such a scheme is the long distances, of up to 50 km, between oilfields and the separation plant. Trunk-lines with multiphase pumps are utilized to overcome the pressure losses and to allow reasonable backpressures at the wellheads.
Considerable savings in operational expenditures were achieved and the integrated concession development approach will enable the operator to apply different improved recovery strategies. The synergies gained from combining improved recovery methods are seen as a prerequisite for commercial application.
This paper aims to illustrate the integration of new field development and mature field re-development. The integration scheme enables the operator to implement improved recovery methods in difficult reservoirs which are not feasible on a stand-alone basis.
Analysis of pressure and water chemistry data from the Devonian and Carboniferous formations of the Lublin Basin indicates that two regional fluid flow systems are operating within this basin. The Devonian basin is the juvenile basin with compaction-induced centrifugal, lateral water movement (before invasion by meteoric waters), and may be classified as prospective. The Carboniferous basin is an intermediate basin with centripetal water movement, artesian properties and invasion of meteoric water.
In this paper author presents the hydrodynamic modelling of hydrocarbon migration and accumulation in the Lublin Basin, Poland. The pressure and water chemistry data have been used to identify hydrocarbon traps within the Devonian and Carboniferous sequences.
A simulation model for the tracer response analysis in naturally fractured reservoirs was developed by double-continua formulation. Waterflooding in dual-porosity dual-permeability reservoirs is first modeled by the streamline approach. Then flow of the water-soluble tracer described by the coupled convection-dispersion equations is combined. First, 1-dimensional convection-dispersion equation is solved along each streamline in the matrix and fracture systems by ignoring the gravity and transfer terms. The concentrations are mapped onto the grid, and corrected with gravity and transfer.
The model is capable of conducting tracer flow and waterflooding simulation in field-scale dual-porosity dual-permeability systems. It is developed particularly for analyzing multiple-well tracer tests in heterogeneous fractured reservoirs.
The model is validated for homogeneous and heterogeneous permeability distributions comparing with results from Eclipse. Effectiveness of the CFL condition and a TVD scheme to control stability and numerical dispersion are evaluated and analyzed. In the heterogeneous case, the saturation fronts and tracer responses from the model are less smeared than those from Eclipse. The model is also run for validation and sensitivity cases with different dispersivity.
Finally, tracer responses for a multiple injection/production scheme in a realistic reservoir including mega-fractures are simulated. Simulations demonstrate the potential of the streamline approach for characterizing heterogeneity of the fractured distribution, and for identifying flow paths.
Evaluation of heterogeneous fracture developments is critically important for assessing the reservoir performance, and yet remains to be a difficult issue. Tracer flow simulation by the streamline approach is particularly useful to interpret and model fracture-matrix systems in terms of flow properties and anisotropy. The streamline-based model is powerful for analyzing tracer response data with readily available visualization.
This paper presents a model for valuing and the multi-stage investment in E&P project using N-fold continuous compound option formula. This model resolves the multi-stage investment decision problem, and extends the notion of a compound option to the n-fold compound option with time-dependent volatility and interest rate. It indeed presents additional insights into the creation of shareholder value of petroleum production and should therefore be used next to more traditional approaches such as Black-Scholes-Merton simulations, especially when tailored to the characteristics of real-life cases of E&P project development processes.
Tyrihans is an oil and gas-condensate field offshore Mid-Norway. Oil reserves are 29 million Sm3 and gas reserves are 35 billion Sm3. The field will be developed as a subsea project with 5 templates having 9 producers and 3 injectors. Production start-up is July 2009.
The field development is innovative in the following aspects:
Cost effective development with a 43 km tie-back to the Kristin platform through an 18?? pipeline. Tie-back is possible because the pipeline will have direct electrical heating to prevent formation of hydrates and to preserve temperature.
Pressure support with both gas injection and raw sea water injection. This is feasible by installing two water injection pumps subsea and using available power and compressor capacity at neighbouring fields.
Extensive use of advanced wells. The oil producers are dual-lateral with approx. 1.5 km horizontal reservoir sections, equipped with down-hole ICVs (Inflow Control Valves) and gas lift. Both main bore and laterals will have 8.5?? hole diameter, made possible by using 8?? expandable liners
Important reservoir management and simulation issues are:
Tyrihans consists of two structures, which cannot be produced independently. Handling gas and water coning in a two-front system and keeping track of fluid contacts are challenging.
The northern structure consists of an 18 m thin oil zone with a gas cap. To simulate recovery from thin oil zones is challenging. The simulation model has horizontal grid, in order to have the required vertical resolution of the oil zone.
Correct modelling of pipeline flow and flow assurance.
The long, single pipeline tie-back makes well testing difficult. Reservoir monitoring and management must then be based on subsea flow meters and gauges. Production optimization will be performed from an onshore support centre.
With the chosen reservoir development strategy high recovery is obtainable. The simulated oil recovery in the southern part is 52%, and the gas recovery in the northern part is 80%.
Tyrihans is an oil and gas condensate field offshore Mid-Norway (Figure 1). Tyrihans Sør (South) was discovered by well 6407/1-2 in 1982 as the first discovery on Haltenbanken offshore Mid-Norway. The well test showed a rich gas-condensate. Tyrihans Nord (North) was discovered the following year, proving a gas cap with a thin oil zone. An appraisal well in Tyrihans Nord in 1996 was drilled through the OWC and proved an 18 m thick oil column. In 2002, an appraisal well in Tyrihans Sør showed a 35 m oil column below the gas cap. With total in-place volumes of 71.4 million Sm3 oil and 57.4 billion Sm3 gas, an independent development of Tyrihans was not economical feasible. In the meantime, the neighbouring gas-condensate field Kristin was under development. It was decided to develop Tyrihans as a subsea (SS) field, tied back to the Kristin platform.
A subsea development makes investments in a platform/vessel unnecessary. However, long tie-backs are challenging with respect to oil recovery and flow assurance. This paper will focus on the SS development facilities and how high oil recovery will be obtained on Tyrihans.
This article introduces a multiscale pore structure characterization method using a combination of mercury porosimetry and image analysis. The method was used to determine the distribution of pore volume by pore size and to estimate the pore-to-throat size aspect ratio. The key idea of the method is that pore size distribution obeys a fractal scaling law over a range of pore size. On this basis, scattering intensity data computed from the measured two-point correlation function and those measured from mercury porosimetry are extrapolated in the size range 0.01 µm < r < 1000 µm, using the known fractal scaling law.
A set of siltstone samples taken from Daqing Oilfield was analyzed through this method. Distribution of pore volume by pore size over the entire range of pore length scales was determined. The results demonstrated significant similarities in the pore structure of all samples. The image analysis results were in qualitative agreement with the results of mercury intrusion/extrusion tests.
The results were also compared with some other samples (including siltstone, sandstone, and dolomite) that had been analyzed using similar methods. It is shown that the surface fractal dimension obtained by analysis of MIP data is consistent with the value obtained by image analysis for different samples with different porosity and permeability.
Novel information on the pore-to-throat aspect ratio is obtained by comparing the complete pore volume distribution (PVD) to the MIP data.
The main challenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enabling technologies in this area is intelligent well completions. Downhole inflow control devices allow for the flexible operation of non-conventional wells. By placing sensors and control valves at the reservoir face, engineers can monitor reservoir and well performance in real time, analyse data, make decisions and modify the completion without physical intervention to optimise reservoir and asset performance. They provide the ability to independently control each valve individually from the surface to maximise oil production and/or minimise formation water and/or gas production. However, they may also be used to address other produced water management issues, such as inorganic scale control.
This paper describes the potential risks posed specifically to intelligent completions by scale deposition. The potential benefits to scale management that ICVs, such as control of scaling brine production and effective scale inhibitor placement, are described. Calculations are performed for a North Sea field with a barite scaling risk, and the cost benefit - specifically to scale management - of using ICVs is evaluated. These calculations demonstrate that intelligent completions significantly reduce the scale inhibitor chemical costs while improved scale inhibitor placement is achieved.
Inflow control valves (ICVs) are emerging as a very promising technology for minimising water production and optimising hydrocarbon recovery.[1-6] However, they also have the potential to address other produced water management issues, such as inorganic scale control, while the operation of the ICV and may in turn be affected by these produced water management issues. This paper aims to demonstrate the possible benefits that can be added to scale management as result of using ICV technology. It also investigates the potential risks posed to intelligent completions by the deposition of scale. The technical feasibility and economic viability of implementing intelligent well technology for scale management was studied. A case study illustrates how the ICVs may be used for scale management. Such a study that links the use of the intelligent wells and scale management has not been reported previously.
Figs. 1 and 2 illustrate some of the issues that may affect the performance of production tubing, and how better access to downhole information can improve the ability to deliver flow assurance.
Most of the oil production in the Middle East comes from carbonate reservoirs, the majority of which are fractured. These reservoirs tend to produce at high rates in their early production period followed by low rates later on, leading to low overall recovery. The challenge is to manage the field and arrest the production decline for a long time.
A reservoir simulation study was performed on a fractured Middle Eastern carbonate field to determine the optimal production strategy. Three possible scenarios - natural depletion, gas injection and water injection were compared. Results indicated that water injection yields better recoveries than gas injection and natural depletion; this is expected since the rock is intermediate to oil-wet, meaning that there was high recovery from imbibition in water flooding. The presence of connected fractures led to early breakthrough and low recoveries in gas injection scenarios. The different physical mechanisms affecting oil recovery are discussed and recommendations are made for other fields with the same fracture properties and wettability
We adapted a scratch apparatus used to evaluate shear strength and stiffness of rocks to use on soft filter cakes, to obtain quantitative information on cake properties for modelling purposes. The modelling will help design better drilling fluids, in terms of their filter cake's resistance to oil production onset. Scratch testing of rock specimens is now a well established method to obtain reliable strength and stiffness measurements as a function of distance along the scratched surface. The apparatus consists of a rigid frame holding a cutter, being pushed at a constant velocity over a rock specimen. A micrometric screw allows the user to choose a precise cutting depth, while a bidirectional load cell monitors the shear and normal forces on the cutter. The shear force can be related to the specific energy of cutting, which in turn correlates with the Unconfined Compressive Strength (UCS) of the rock. New low-resolution load cells have been installed in anticipation of the orders of magnitude lower expected values when scraping filter cakes. Rocks were exposed to different fluids to assess the impact on filter cake quality and inner filter cake properties. The effect of the internal filter cake on the rock was also addressed by scratching the rocks prior to filtration and once again after, scratching through the filter cake, on the exposed rock face. Quantitative and detailed probing of filter cake elastic properties is now possible using the scratch method. Concerns about removing the filter cake all at once (especially when OBM systems are tested, known for their low adhesion) turned out to be unfounded; the tool was capable of scraping out clean, well-defined cake layers, down to a thickness of 0.1 mm.