Kalol field is a major oil-producing field of Ahmedabad Asset, ONGC. The field has 40 years of history with over 500 wells drilled and 11 potential hydrocarbon-bearing layers exploited. Over the years data has gathered differently into substantial dimension. A field-level integrated database system has been developed in-house using Microsoft Office's Access module. Apart from regular data management tasks, the package is designed to generate streaming input data files for two popular software. As the package is equipped with strong relational back-bone, data updating is instantaneous and it remains integrated sans any duplication or redundancy. The package is in use for Kalol field most effectively and indeed a suitable quick-run data management tool for any oil-field, small or large.
Concerns are raised of a personnel and skills shortage in the Oil & Gas industry.
Two solutions can mitigate the problem: 1. Make more efficient use of the present pool of people 2. Promote the Oil & Gas industry at the universities and to young professionals in other industries.
This paper will describe why there is a reason for concern and how new technology will be part of the solution to overcome a personnel shortage.
Over time pipelines in the field, transporting high-pressure gas, have exhibited severe external wear at support locations, especially near bends, due to expansion/contraction with respect to climatic conditions.
This paper describes on-stream inspection survey techniques and the subsequent repair/inspection methods carried out, to ensure that pipeline integrity is maintained. The first gas transmission lines were constructed around 30 years ago, meeting the code requirements of ASME/ANSI B31.8, with an operating pressure of approximately 1050 psi. In July 1998, at one location, a 12" gas transmission line leaked due to external wear of the pipe at its point contact with a transverse support.
This paper also focuses on the significance of design location class, field investigation, corrective & preventive measures, repair & acceptance methods.
Transformation of borehole logging measurements into accurate and precise porosity, lithology, permeability and fluid saturation data is the most important result of a petrophysical analysis.
A fundamental petrophysical problem is how to minimize systematic and random errors associated with data acquisition from different logging tools, variable borehole conditions and reservoir properties. Historically, errors were minimized by increasing the number of logs and/or calibration of results to core data. In the 1980's, a major development in petrophysics was the utilization of error minimizing routines to optimize the accuracy of petrophysical results. This optimization analysis combines input data with a set of response functions to find the best solution by minimizing the differences between predicted answers and actual inputs. Even though this technique appears to have technical advantages, acceptance has been limited due to underlying complex mathematics and consequently, the process is less understood.
A recent study was completed to determine the strengths and weaknesses of this type of analysis on Ghawar field, Saudi Arabia. Due to its vast areal extent, unique reservoir properties and extensive logging and core data, this field provided an ideal basis to evaluate optimizing analytical models. Data from several logging companies was used to show the combined effects of tool types and vintages, borehole conditions and reservoir properties on the utility of optimized petrophysical methods in Ghawar field.
Kalol field has multi-layered reservoirs with 11 pay horizons. Layers VII and X have better sand thickness. Gross lithology is mainly siltstone. The permeability ranges from moderate to poor and the primary reservoir drive mechanism is depletion. The reservoir pressure has declined from super-hydrostatic to substantially sub-hydrostatic at present. The productivity of vertical wells has fallen sharply and the field production rate has decreased. The well spacing is 600-700m, static bottom hole pressure shows high degree of variation. Two areas in sand KS-VII and KS-X were selected for drilling of multilateral wells. The wells have been drilled and put on production. The results are encouraging and the technology is proved to be an effective option for redevelopment of the field.
The Al Khalij field, located offshore Qatar, was discovered in 1991 and put into production in 1997. The field is original in many aspects. It is one of the few carbonate reservoirs with a stratigraphic closure, the oil being trapped in the upper part of a monocline due to a lateral variation in reservoir facies. In addition, the reservoir lies within the capillary transition zone and consists of a succession of highly conductive oil bearing layers ("drains") in between matrix layers of poor permeability.
Due to the complex reservoir architecture and the large uncertainties in the reservoir dynamic behavior, the field has been developed in several stages to improve understanding and minimize risks.
This paper will discuss on the development of Al Khalij field and will illustrate how advanced technological solutions were applied to overcome complex geological and reservoir problems in order to enhance reservoir performance and well productivity. More specifically the paper will illustrate how:
High-resolution 3D seismic has revealed additional areas for development, which were previously considered to be uneconomic.
Innovative well design in a stair-step manner was implemented to intersect productive layers and increase drainage efficiency with a limited number of wells.
Stimulation and completion techniques were adapted to optimize productivity while limiting water production.
Water injection was implemented in the field after validation of its effectiveness through pilot water injection, including tracer test, and through reservoir simulation studies.
ALKHALIJ: A Complex Field
A subtle closure
The Mishrif formation is the main reservoir and consists of Cenomanian limestones. The depositional environment corresponds to a carbonate platform with rudist shoals.
The Al Khalij field is a stratigraphic trap (Fig. 1). The lateral stratigraphic seal, globally N-S orientated, is provided by lagoon mudstone deposits developed to the west and recognized on wells located a few kilometers west of Al Khalij field.
The top of the Mishrif reservoir is partially eroded with maxima of erosion to the NE and the SE as a consequence of the uplift of the Rostam field salt structure. The cap seal is provided by the Laffan shale.
A complex internal reservoir architecture
Vertically, the reservoir is subdivided into two main stratigraphic units (Fig. 2), separated by a maximum flooding surface (MFS 7):
The upper reservoir unit is currently being produced in the central and southeastern parts of the field. Towards the North, these layers are partially eroded.
The lower unit is water bearing in the current producing area while it is oil bearing in the North and will be developed in 2003-2004.
The top and base of the reservoir can be interpreted on 3D seismic (Fig. 3) which provides a control on reservoir structure, erosion limits and volumetrics.
The max effective hole-diameter mathematical model describing flow of slightly compressible fluid through a commingled reservoir is solved rigorously with consideration of wellbore storage and different skin factors. The exact solutions for wellbore pressure and the production rate from layer j obtained for a well producing at a constant rate from a radial drainage area infinite and const pressure and no flow outer boundary condition are expressed in terms of ordinary Bessel functions. The numerical computation of these solutions is made by Crump numerical inversion method and the behavior of the systems is studied as a function of various reservoir parameters. The new model is compared with the real wellbore radii model. The new model is numerically stable when the skin is positive and negative. The real wellbore radii model is numerically stable when the skin is positive. Because the curves explicitly include skin factor and other reservoir parameters, the techniques is expected to be more accurate than the real wellbore radii model. The automatic history matching technique has made it possible to accurately determine individual layer properties and wellbore parameters.
An artificial neural networks (ANN) model has been developed to provide accurate predictions of mud density as a function of mud type, pressure and temperature. Available experimental measurements of water-base and oil-base drilling fluids at pressures ranging from 0 to 1400 psi and temperatures up to 400 °F were used to develop and test the ANN model. With the knowledge of the drilling mud type (water-base, or oil-base) and its density at standard conditions (0 psi and 70 °F) the developed model provides predictions of the density at any temperature and pressure (within the ranges studied) with an average absolute percent error of 0.367, a root mean squared error of 0.0056 and a correlation coefficient of 0.9998.
Mubarraz area which is located in the center of the giant Ghawar field in Saudi Arabia has several wet crude handling facilities referred to as gas oil separating plants or GOSPs. These GOSPs process Arabian Light crude and their primary function is to separate oil, water and gas. In the past it has been observed that the usage of demulsifier varies from GOSP to GOSP. Some GOSPs, like GOSP-2, consume higher dosage of demulsifier compared to the other GOSPs. At the request of operations engineering personnel, and in partnership with them, a research study was initiated to investigate the causes of variable demulsifier usage in GOSPs, factors that stabilize these emulsions, and to evaluate the relative performance of demulsifiers. The primary objective of this study was to optimize the use of demulsifier in GOSPs while meeting crude and water specifications.
This paper provides results of an investigative study conducted to determine the causes of tight emulsions in GOSPs. The emulsions from different GOSPs were characterized in terms of their tightness using Emulsion Separation Index1. The study has also determined the causes of emulsion tightness in these GOSPs. These include crude oil temperature at the GOSP, percentage of wells squeezed with scale inhibitor, and overall GOSP watercuts. Based on these results several recommendations have been made to optimize demulsifier usage, ways to reduce emulsion tightness in Mubarraz field and test promising demulsifiers that should result in cost savings. The paper describes the partnership with operations and production engineering to optimize demulsifier usage at the GOSPs.
This paper describes a development strategy with peripheral water flood for Haradh Arab-D reservoir, a large oil bearing carbonate part of the greater Ghawar field. In a heterogeneous matrix permeability background, geological discontinuities such as faults, fractures, and stratiform high permeability streaks lead to a decisional divergence between development options. In this regard, optimizing the field development plan aims to find a proper balance among several conflicting requirements.
In the case of Haradh Arab-D, the field development options are divided into two components. The first component is a development scheme that is the most cost effective with respect to production plateau, oil recovery and reservoir conformance. This option involves a multi-disciplinary team addressing the development challenges by extracting information from nearby development experience, quantifying uncertainty with deterministic and stochastic modeling techniques. An array of different reservoir simulation models (Single media full field model, Dual-porosity-permeability model, Local grid refinement model, and Streamline model) was used for the purpose (1). This results in a preliminary development plan with the application of the horizontal well options with respect to well placement, horizontal direction, completion interval selection and the length of the horizontal section.
The second component, the focus of this paper, is the sensitivity analysis and risk assessment running concurrently with reservoir simulation to develop a Pareto chart for different reservoir parameters such as Fracture density and connectivity, Super-permeability layers, Skin damage, Aquifer size, and Kv/Kh ratio. The most sensitive parameters with respect to oil recovery are identified for re-assessment and further improvement and optimization of the development plan. Data acquisition program, reservoir performance evaluation and production injection strategies are conducted with these sensitivities in mind. They are executed with the highest priorities given to the most sensitive parameters.
In order to ensure that the target objective is achievable, wells drilled during the initial development phase are tested to validate the development strategy. Monte Carlo simulations again are run on periodic basis with actual field data input to further optimize the development.