In this paper we will present the Shell workflow for 4D seismic. This workflow contains several stages: feasibility study, acquisition design, data processing, data interpretation and final feedback loop of the results to the geological and dynamic reservoir models; which in turn are used for field development planning and well proposals. Furthermore, we will also show some case studies from a variety of fields ranging from Carbonates to Sandstone and Turbidities.
The first stage of this workflow is the feasibility study that is based on measurements of rock properties and the currently used reservoir simulation model. In the case the results of the feasibility study prove to be positive we proceed to the next step. The second step involves the survey design, acquisition and in-house processing. Parallel to this process, the reservoir simulation scenarios and history matching are carried out. With these stages finished seismic data interpretation takes place. The results of the seismic data interpretation reveal the most appropriate reservoir simulation scenario. Further fine-tuning for the selected reservoir simulation and geological scenarios is then carried out to match the 4D seismic. Our experience with the fields we have processed so far has proved to find some by-passed pockets of hydrocarbons. In this paper we would therefore like to share our experience in these fields.
The Bahrain field is an asymmetrical anticline trending in the North-South direction. The field was discovered in 1932. The field is a multi-stack carbonate and sandstone reservoirs most of them oil bearing. The fluids range from tarry oil in Aruma zone to dry gas in the Khuff zones. The geology of the field is extremely complex with a large number of faults especially in the Wasia group formations, which contain the major oil reservoirs of the Bahrain field. These reservoirs are at different stages of the production cycle.
Following a 3-D seismic acquisition campaign in the year 2000, Bapco took up an integrated study to develop numerical models as the main tool to assess alternative production mechanisms. This integrated study faced a significant number of challenges, which had to be overcome with innovative ideas.
The challenges included representing communication between reservoirs through faults, complex rock and fluid distribution from heavy oil to gas condensate, gas injection, aquifer encroachment and fracture intensity. Although the hardware required for handling the large simulation models was meticulously selected based on benchmark data of the various machines, the geological complexities posed serious problems while running the simulation models.
This paper describes the challenges faced by the joint Bapco-CGG team and the approaches adopted to overcome these challenges.
Koskinen, Jukka (Neste Engineering Oy, Fortum Oil and Gas, Finland) | Manninen, Mikko (VTT Processes) | Pattikangas, Timo (VTT Processes) | Alopaeus, Villo (Neste Engineering Oy, Fortum Oil and Gas, Finland) | Keskinen, Kari I. (Neste Engineering Oy, Fortum Oil and Gas, Finland, Helsinki University of Technology) | Kolehmainen, Eero (Neste Engineering Oy, Fortum Oil and Gas, Finland)
CFD modeling of drag reduction (DR) by polymer additives dissolving in hydrocarbon was carried out in pipe flows and in a rotating shear viscometer. Two-layer turbulence model describing the damping of turbulence by the DRA molecules in the near-wall regions was applied. The von Karman constant in the near-wall region was used as the model parameter. Extensive measurements of the DR effect for a rotating viscometer were performed at different Reynolds numbers, apparent molar masses and concentrations of DRA. The model with only one fit parameter was able to reproduce the experimental results both in pipe flows and in the rotating viscometer. Experimental results were utilized in relating the model parameter to the relevant physical properties.
The phenomenon of drag reduction by low concentrations of long-chain polymers has been widely studied since Toms discovered the effect more than 50 years ago. In long oil pipelines, the pumping capacity can be significantly increased and pumping costs decreased by applying small amounts of drag reducing additives (DRA). Up to 70 % reduction of pressure loss in pipe flow has been achieved.
The DR-effect has been studied mostly in pipe flow obviously because it is the most important application [1-3]. Using pipe diameters larger than 40 mm, DR effects can be measured accurately at high Reynolds numbers also for high viscosity (3×10-5 m2/s) oil. Pipeline construction may be, however, rather expensive and the measurements time consuming. The advantage of the pipe flow measurements is the large amount of general knowledge about turbulent flow in pipes.
In a spinning wheel consisting of a ring-shaped pipe and equipped with torque measurement, the pressure loss can be measured accurately with a small amount of fluid and without degradation losses .One possible drawback of this method is the rather short liquid volume length providing only partial DR-effects.
A new method is presented for the estimation of parameters for a circular aquifer by nonlinear regression analysis using numerical inversion of Laplace transform. The parameters estimated are the relative aquifer size ReD, the storativity hfCt and the transmissibility kh/µ. These parameters are necessary to calculate water influx needed in performance prediction of oil and/or gas reservoirs by material balance based methods.
Water influx data are fitted to the van-Everdingen and Hurst (VEH) unsteady state solution to obtain the required aquifer parameters by nonlinear regression analysis using the method of least squares. Because the solution in Laplace space is simpler than the solution in the real time domain, numerical inversion of Laplace transform was used to obtain the partial derivatives of the VEH solution with respect to aquifer parameters needed for least squares method. The Levenberg method was used for parameter estimation to guarantee convergence. This procedure proved to be efficient and free of computational and convergence problems encountered when using real time solution.
Two approaches are used to represent the variable pressure history: the step pressure SP and the linear pressure LP methods.The two approaches are used to generated water influx data and the values obtained by both methods are compared with the actual (assumed) data. The LP method is found to yield more accurate results and is used in the parameter estimation algorithm.
The developed algorithm can be applied for performance prediction of oil and gas reservoirs under water drive and for the simultaneous estimation of original hydrocarbons in place (OHIP) and aquifer parameters based on material balance equations.
The Early Aptian carbonates of the Mauddud Formation form giant hydrocarbon reservoirs in North Kuwait. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity. A robust depositional model driven by sequence stratigraphy, petrophysics tuned to dynamic data and innovative static modeling techniques were used to characterize this complex reservoir.
The Mauddud carbonate sedimentation took place in a low angle ramp setting. The basal part of Mauddud consists of shales and low energy carbonates deposited in a transgressive systems tract. The main reservoir was deposited during the subsequent highstand systems tract. High-energy inner ramp grainstones preserve the best primary porosity and permeability. Reservoir quality deteriorates in mid ramp to inner ramp wackestones and mudstones.
Diagenetic carbonate concretions destroy porosity and permeability. It is more pronounced in mud-rich packstone / wackestone fabrics. Early hydrocarbon emplacement has terminated concretion growth in crestal areas of the field whereas concretion formation and subsequent reservoir degradation continued in the water leg through late diagenetic stages. Rudistic floatstones, radially fractured concretions and small-scale fractures in low-porosity brittle rocks are the main thief zones in the reservoir.
Through the integration of core, openhole logs, production logs, and pressure transient analysis, a deterministic permeability model has been developed that characterizes the reservoir. Logs have been reprocessed to identify zones of secondary porosity (enhanced permeability) and fracture-prone zones. Porosity-Permeability transforms for matrix properties and fracture-prone intervals were developed. This methodology results in log-derived permeability profiles that match production log profiles and well test Kh estimates.
A fine Geological model with 85 layers and 2.5 million cells has been built to capture the primary depositional units. The horizons bounding the flow units are major flooding surfaces. The lithofacies associations have been modeled as composite objects restricted to facies belts. As porosity was observed to be decreasing towards the flank, trend modeling has been used to model the effective porosity. Another geological model with 166 layers was built to capture the small-scale heterogeneity caused by vuggy zones and fractures. The vugs and fractures have been modeled as objects restricted within an area demarcated by poorer seismic coherence. The Matrix permeability was enhanced by vuggy permeability and fracture permeability.
The paper describes the challenges in reservoir description and static modeling of this complex reservoir in detail.
In recent decades Bahrain has experienced a rapid growth in gas demand for industrial use, electricity generation, gas injection, and artificial lift. The main source of gas for these needs is the Khuff reservoir. The Khuff gas is currently being produced from 29 prolific gas wells.
To enhance the productivity of the Khuff reservoir a matrix acid stimulation program was undertaken using coiled tubing and a temporary non damaging gel plug system with complete regained permeability to isolate the high-permeability producing zone while the low-permeability gas-producing zone was being stimulated. Because the isolated zone is also producing, the gel system has to be completely non damaging with full regained permeability to this isolated formation.
The success of stimulating a low-permeability interval where a high-permeability producing zone is also present is primarily dependent on the ability to divert the respective stimulation fluid into the zone of lower permeability and productivity. Several methods are commonly used to divert the stimulating fluid in the non productive zone. These methods are dependent on the type of stimulation and configuration of the completion.
If coiled tubing is used for through-tubing stimulation in cased holes, inflatable packers are normally considered for isolation. However, inflatable packers have limited expansion ratios and pressure capabilities. The previous use of ball sealers gave very limited results of only 10% incremental gas production.
This paper will present the successful stimulation techniques and results of a unique and cost effective solution for a well where two intervals with different permeabilities were isolated without the high risks and costs of using a mechanical packer. Coiled tubing was used to stimulate the lower interval while the upper producing interval was isolated using a temporary chemical packer. Temperature in this well exceeded 270°F.
The Salt Creek Field, located approximately 110 miles northeast of Midland, TX, is a heterogeneous, Pennsylvanian-aged carbonate build-up in the Permian Basin. Successive implementation of infill drilling and improved recovery processes, coupled with effective reservoir management, have led to oil recovery of over 50 percent and expected ultimate recovery as high as 60 percent.
Salt Creek field was discovered in 1950 and a centerline water injection program began in 1953. A 40-acre development program was initiated in 1970 and was completed in 1984. The waterflood pattern was also changed from a centerline drive to a field wide inverted nine-spot. In 1985, a reservoir continuity study led to a 20-acre infill drilling program that added over 150 wells, changing the pattern to a five-spot. A miscible carbon dioxide (CO2) flood was initiated in 1993, and then expanded to the underlying residual oil zone.
Reservoir management has been a key element in maximizing recovery at Salt Creek. Consistent acquisition and maintenance of appropriate well and reservoir data has allowed detailed zonal tracking of production and injection volumes (CO2 and water). Geologic models, in combination with production logs and production data, have been used to manage and optimize CO2 and water injection at the flow unit level. Effective communication processes have been established between the field operators and the technical staff to calibrate engineering and geologic data with field experience and to enhance real-time decision making. A 3D seismic survey covering the entire field was acquired in 2000 to better define productive field limits and reservoir geometry. Currently, a study integrating engineering and geoscience data is underway to further improve reservoir characterization. The study is expected to result in improved sweep efficiency through better conformance control and additional drillwells to capture unswept reserves.
During matrix acidizing operations performed on oil wells, post-treatment analysis is often overlooked due to the lack of a simple, robust tool. Current methods rely on the equations used for well tests analysis, either steady state or transient, and focus on the computation of the skin factor. However this computed skin most often proves unreliable due to the complexity of the treatments, which routinely involve multi-layered reservoirs and advanced diversion techniques, i.e. phenomena that are not handled by the well testing equations. As a result, operators content themselves with providing clients with a plot of pump rate and wellhead pressure versus cumulative volume - or time. Unfortunately, any interpretation performed with this type of plot has more in common with divination than science.
In this paper, a new way to plot matrix acidizing treatment data is presented. The inverse injectivity index and its integral are plotted versus time. This is similar to Hall plots, which are used to monitor water injection wells, but it corrects for the rate changes occurring during acidizing treatments. The concavity of the integral then visually indicates whether the treatment is achieving stimulation or diversion, and this behavior can easily be identified despite the noise usually associated with any field measurements. As a side benefit, this technique also provides means to verify the average reservoir pressure value.
The theoretical basis of this new plot is discussed and its usefulness assessed using data generated by Pericles, a matrix acidizing numerical simulator. A field case is then analyzed and is used as an opportunity to once again emphasize the need for reliable bottom hole pressure data, whether measured or calculated, without which any analysis is inherently flawed.
In crude oil production, the generation of heavy oil/water emulsions can result in a significant drop in the production rate due to the high viscosities of the emulsions. The strong agitation and mixing that takes place at the inlet of the well bore together with the presence of the naturally existing emulsifying agents in the crude contribute to the formation of the emulsion. A number of methods can be used to mitigate this problem such as the injection of surfactants into the formation and surface treatment. The objective of this paper is two-folds. Firstly, the results of an experimental program carried out to evaluate the efficiency of several surfactants to demulsify crude oil / water emulsions are presented. Secondly, a novel cost effective technique for injecting the surfactant into the well utilising existing gas lift facilities at the well heads is described together with a number of other techniques which have been tested for treatment of emulsions.
The experimental study was performed on crude oil/water emulsion samples obtained from two sandstone reservoirs in the Bahrain field. The measurements included effects of surfactants on the degree of demulsification, surface tension and shear viscosity. An optimum surfactant/emulsion volume ratio of around 1.5 to 2% was noticed in most cases for the specific wells investigated. The addition of surfactants considerably reduced the shear viscosity and surface tension of the emulsion. As expected the surface interfacial tensions decreased with increasing temperature.
The objective of this paper is to share the knowledge mapping techniques and experiences of those involved in this activity.
The purpose of a knowledge map is to show people in the organization where to go when they need expertise or have expertise to share. A knowledge map is a picture of what exists in the company as well as where it is located. It therefore can be used as a tool to discover opportunities to be exploited and gaps to be filled. When the same reservoir has different production policies for different portions of the field, Planners from all teams suffer from incomplete data. Information is shared when available, as in the case of the full-field reservoir model. But this is not thought to be optimal, when other reservoir studies have been conducted in isolation and expertise is not shared. A more coordinated approach is required that would continuously bring together all the available knowledge and make it always freely available to analysts and decision makers.