Summary This paper discusses experimental work associated with the evaluation of asphaltene precipitation for a field in Abu Dhabi, UAE. This reservoir is in the early stages of development and will be put on production using a combination of gas-, water-, and water-alternating-gas- (WAG) injection schemes in early 2006. The field has not shown operational problems resulting from asphaltene precipitation during primary production. Laboratory experiments using the transmittance of an optimized laser light in the near-infrared (NIR) wavelength (˜1600 nm) were used to first confirm the stability of asphaltene in the reservoir fluid. Two cases covering the expected extremes in terms of the field gas/oil ratio (GOR) were evaluated. Isothermal depressurization tests were also conducted at reservoir, wellhead, and separator temperatures (250, 190, and 130oC, respectively). Several additional light-transmittance experiments were conducted to evaluate the asphaltene-instability regions resulting from reservoir-fluid contact with various concentrations of rich gas and carbon dioxide (CO2). Measurements using high-pressure filtration were also collected to quantify the bulk precipitation of asphaltene with various molar concentrations of gas. Finally, tests were conducted using state-of-the-art technologies to evaluate the consistency of the initial NIR runs. These technologies involved the use of a spectral-analysis system (SAS) to evaluate asphaltene-particle size and growth rate and high-pressure microscopy (HPM) images to visually confirm the measurements. Results indicated that rich hydrocarbon gas in contact with reservoir fluid destabilizes asphaltene. The amount of the bulk precipitation increased with higher concentrations of rich gas in the reservoir fluid. Particle sizes were estimated to be in the range of 0.5 to 1 µm. The effect of CO2 was found to be less severe with regard to asphaltene instability. Introduction Because the reservoir is still in early development, and will not be put on production until early 2006, a feasibility study was undertaken to evaluate the potential of improved oil recovery (IOR)—by using a combination of gas-, water-, and WAG-injection schemes—as well as asphaltene compatibility with various injection gases. To cover the range of reservoir fluids encountered in the field, two extreme cases of GOR were evaluated. A summary of the reservoir-fluid properties for each of these fluids is provided in Table 1. These properties confirm a typical black-oil reservoir fluid. Properties to note for the stock-tank oil (STO) include an n-C7-insoluble asphaltene content of approximately 1.0 wt% in Fluid A and approximately 0.5 wt% in Fluid B. Wax contents (Universal Oil Products 46 Summary Foam stability is an important parameter for foam fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH [particularly with carbon dioxide (CO2) systems], and dynamic-flow conditions that can have unexpected influence on the foam's performance. A laboratory apparatus has been constructed for measuring the rheology of circulating-foam fluids to 400°F and 3,000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter, and piping for loading a foam of the desired quality using either nitrogen (N2) or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing. The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continuously adjusted, to ensure a constant shear rate in the tubing, by the software using continuous mass-flowmeter input. Results relating to CO2 and N2 foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future. Introduction Foam-fracturing fluids are used in approximately 40% of all fracturing-stimulation treatments executed in North America. Foam-fluid functional properties, such as proppant-carrying capacity, resistance to leakoff, and viscosity for fracture-width creation, are derived from the foam structure and the external phase properties. Moreover, the foam must have structural stability to maintain its performance throughout the treatment. A major objective of this work was to develop an efficient method of evaluating the time-dependent properties of foam-fracturing fluids under meaningful conditions. The reasons for this objective are to evaluate the effectiveness of surfactants and to determine the two engineering parameters, behavior index (n') and consistency index (K'), used by fracturing simulators to estimate treatment operating parameters and fracture geometry. 64) of 1.9 wt% and 2.9 wt% were measured in Fluids A and B, respectively. The respective STO cloud points were 102 and 99oF. The wax content did not appear to raise any concern because there was no evidence of an operational problem in the field related to wax. Also, the subject reservoir is not expected to cause operational problems resulting from asphaltene precipitation during primary production. Asphaltenes are high-molecular-weight organic fractions of crude oils that are soluble in toluene, but insoluble in alkanes (e.g., n-heptane and n-pentanes). Asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions. They may start to precipitate once the colloidal suspension is destabilized, which is caused by changes in temperature and/or pressure during primary depletion.1 Asphaltenes have also been reported to become unstable as a result of blending (commingling) fluid streams,2 as well as by gas injection during IOR operations.3–7

Tight carbonate reservoirs, although less well understood and believed to require higher development costs and risks than conventional reservoirs, have become an important resource. Historically, tight reservoirs have been unpopular and unfavorable with geologists and reservoir engineers mainly due to difficulty associated with their development with no commercial productive value. Recently, with the increase in demand for oil and continuous development of new technologies, the time is right to carefully examine and develop such reservoirs. This paper discusses the development of one of the tightest carbonate reservoirs offshore Abu Dhabi, UAE. Initially, this reservoir was not planned to be developed based on the appraisal data collected. The average reservoir permeability is around 1 mD with a productivity index of 0.4 bod/psi. However, an intensive work was performed to evaluate the reservoir potential as being commercially attractive. Such process included gathering of additional data during the development of a major reservoir located below and the review of the core and test permeability data across the reservoir. Several model scenarios were created both on static and dynamic sides as well as an evaluation of the uncertainties and associated development risks. Effectiveness of the study took place when drilling horizontal wells across the most permeable intervals resulted in a production five times higher than expected. This resulted in a decision to embark on the field development and additional production data gathering for development optimization. Introduction The subject reservoir is a complex tight carbonate reservoir; it is an oil reservoir with a relatively large gas cap located on land, island, shallow and deep marine areas. It has been penetrated by several wells during the field development implementation of other reservoirs. Thus, it's well controlled in terms of structure, fluid contacts and porosity distribution also it has considerable proven GIP/OIP volumes. The reservoir is clearly dominated by lime-rich sediments with only a weakly effective micro-pore system. Locally, in the lower part of the Zone, framework pores within the Bacinella structures remain open. Small scale, hair line fractures associated with stylolites were observed in the upper part and may provide preferential flow. The cored wells resulted in a very low permeability values with an average of 1 mD. It was also production tested through DST and Rig-On-site (ROS) for a short duration in several wells. The test rate confirmed the tightness of the reservoir where in some wells; pressure test analyses were carried out and showed very low productivity index ˜ 0.4 bod/psi only within a maximum KH value of 44 mD-ft. However, a trend of permeability enhancement was observed towards the northeast of the field from cores and logs data. This trend was selected as the first to be considered for any future development plan. The main challenge in evaluating tight reservoir is how to identify the reservoir potentiality or deliverability to recover quantified reserve. Most of the tight reservoirs that have huge gas cap are developed for gas rather than oil rim, which is economically and operationally less attractive. Recently, with the increase of the oil demand and continuous development of new technologies, it was decided to develop the subject reservoir under depletion using a limited number of wells to contribute to a daily production rate of 500 STBOPD per well and also perform a feasibility study for full field development.

Identifying opportunities in the installed capacity and proactively mitigating the limiting factors are paramount objectives for pursuing profitable production assurance. Although integrated asset modeling has been the de facto technology for supporting production planning and optimization work processes, its application is not fully adopted as it presents challenges when attempted to be used in a large-scale of multiple oil and gas assets. This paper describes ADNOC’s innovative approach to develop a large scale subsurface to surface integrated asset modeling (LSSSIAM) solution by focusing on the desired business outcome. The paper introduces a new concept of right complexity modeling (RCM) to drive the type and level of complexity of the model/simulation based on the desired business outcome and other factors that influence the quality of the decision-making process. The methodology has been applied on a large-scale of multiple assets for effective production assurance that integrates the subsurface to the surface physical phenomena as required by the desired business outcome—the technical assurance of production plans within the context of a country. For the presented example, the proposed methodology resulted in the design of a solution where the subsurface phenomena are represented with a data-driven model to specifically address the requirements of the decision-making process which the solution supports. This resulted in the development of a first-of-its-kind countrywide production model that rigorously considers the properties and physics from the wells to the point of supply while also considering the subsurface phenomena as related to the production potential of the reservoirs and wells. The solution leverages the rigor of first-principle reservoir models to obtain a data-driven proxy model suitable for integration with a first-principle model covering more than 7,000 wells, multiple network and asset facilities, and a supply point transfer countrywide network. The solution can run in a matter of seconds, allowing for the optimization of a desired objective function or the effective analysis of operational scenarios, which can include short- and mid-term production assurance, opportunities identification to increase production to capture value opportunities from a country-wide production capacity context, and compensating for possible shortfalls resulting from unplanned operational disturbances in other assets.

Full field development plan of a complex carbonate reservoir on land, islands, shallow and deep marine areas is a complicated issue at a high cost (building artificial islands, drilling from shore using highly deviated wells with long reach, etc.). This paper presents a multi-disciplinary approach for the full field development plan of the X field off coast Abu Dhabi. The reservoir under study was discovered in 1969 being an oil bearing reservoir with a thin gas cap. It has good porosity development (14–18 %) with low permeability (0.4 to 5 mD). Two strike-slip fault patterns (W-E and NW-SE) were mapped seismically. Image logs and dynamic data suggest that fractures are rare across the reservoir. The field exhibits a low relief structure (250 ft) with dips of less than 2 degrees down flank and a pool area closely to 500 sq. km. The reservoir shows lateral variation in fluid and petrochemical properties. A full field compositional model is being used to evaluate the field reservoir performance under various development scenarios. The field has been in Early Production Scheme (EPS) since early 1990 and has been on stream since December 2005. Due to reservoir tightness, coupled with the fact that the field is located on an environmentally sensitive area offshore Abu Dhabi, it is being developed with long horizontal wells drilled from clusters (land, island and artificial islands). Accordingly, most of the drilled wells are highly deviated and some of them are in the category of ERD (Extended Reach Drilling). For this reason, depth uncertainty associated with large departures and complex trajectories revealed to be an important component of the reservoir models uncertainty. Uncertainty analysis and risk mitigation were therefore tackled by the team as a priority for the field development. This paper addresses the uncertainty related to a low relief structure and the masking of shallow velocities, the depth uncertainty associated with high departure horizontal wells and the spatial petrochemical heterogeneity. Static and dynamic reservoir models have been built using information from wells and 3D seismic data. An integrated modeling approach involving Geology, Geophysics, Petrophysics and Geostatistics were applied to build the frameworks and property models. Both deterministic and stochastic techniques were used to populate the models with porosity, permeability and saturation. Multiple realizations were generated for the uncertainty analysis. Also discussed in this paper is the integrated work associated with the development plan optimization for this reservoir. A full field development plan was set using a 3-D compositional simulation model and calls for five spot gas injection patterns on the crest and staggered line drive on the flank using WAG injection. This required the drilling of 57 horizontal wells (23 injectors and 34 producers) in a shallow marine area. Subsequently, a detailed drilling strategy /development plan was set to develop the reservoir. The subject reservoir was put on production using a combination of Gas/Water/WAG injection schemes in late 2005 early 2006. Field History Location and Geological Aspects The field is located in the northeast part of Abu Dhabi, UAE. The field lies in a coastal marine area, which includes Land, Islands, Sabkha and Shallow-Marine environments (water depth varies from zero to eight meters) and Figure 1 displays the different depositional environments is the area. Being a very sensitive area concerning geological and wildlife issues, some concerns were raised at the time of the development in terms of environment and also some problems were faced while acquiring the 3D seismic during to a mix of shallow marine and land acquisition.