Nikolinakou, M.A. (Bureau of Economic Geology, The University of Texas at Austin) | Luo, G. (Bureau of Economic Geology, The University of Texas) | Hudec, M.R. (Bureau of Economic Geology, The University of Texas) | Flemings, P.B. (Bureau of Economic Geology, The University of Texas at Austin)
We use elastoplastic geomechanical models (Modified Cam Clay) to predict how stresses and pore pressures evolve in mudstones bounding a salt body. We show that the loading caused by visco-elastic salt relaxation processes can induce pore pressure perturbations that extend kilometers away into the sediments. The time scale of dissipation of these perturbations is on the order of millions of years, suggesting that pore-pressure anomalies should commonly be present in sediments near salt systems. Because previous models have not coupled changes in the stress field to changes in the pore-pressure field, they are unable to predict the interdependence between pore pressure and stress. However, this interdependence is critical to well-bore design, as the range of safe drilling pressures is defined between the values of the minimum principal stress and the wall-rock pore pressure (safe-mud window). Our coupled poro-elastoplastic models show that underpressures can lead to sudden pressures drops under the salt, while excess pore pressures close to the flank can shift the safe-mud window to higher values. These results may provide insight into pressure perturbations that have been observed in deepwater drilling near salt. Coupled geomechanical models such as the ones presented here can offer more reliable predictions of stresses and pore pressures in salt systems around the world.
The reliable prediction of pore pressures around a drilling well is critical for the stability of a wellbore. The ability to anticipate and plan for sudden changes in the fluid pressures can not only spare millions of dollars, but also prevent the loss of human lives and environmental pollution. Drilling problems are often reported adjacent to, or beneath salt bodies, leading to additional expense or even abandonment [1-5]. This is an important concern for the drilling industry, considering that a significant number of hydrocarbon reservoirs around the world are found below salt bodies [6, 7]. From a geomechanical point of view, non-geostatic stresses and non-hydrostatic pore pressures are expected around salt structures. Salt is a viscous material that cannot sustain deviatoric stresses. Under differential loading it flows and changes shape, and eventually relaxes to an isostatic state. The emplacement of a salt body may cause significant deformation of the surrounding sediments, perturb their state of stress and create local overpressures. The objective is, hence, to estimate the stress changes within the sediments that result from the emplacement and relaxation of the salt. Because wall-rocks are porous materials, stresses are coupled to pore pressures, according to the effective stress principle  and the theory of pressure dissipation . Coupled mathematical models have been used extensively in geotechnical practice [10, 11] and other poromechanical fields , however they have seen restricted application in the hydrocarbon industry because they are computationally intensive, and they require more specialized laboratory testing programs for the model input parameters. In some cases, the presence of pore pressures is modeled by considering a porepressure profile [28-30]; however, pore pressures are assumed constant (usually hydrostatic) and are not updated to reflect perturbations caused by the solid mechanical model.
Wang, Yingying (Offshore Oil/Gas Research Center, China University of Petroleum) | Duan, Menglan (Offshore Oil/Gas Research Center, China University of Petroleum) | Wang, Deguo (Offshore Oil/Gas Research Center, China University of Petroleum) | Liu, Junpeng (Offshore Oil/Gas Research Center, China University of Petroleum) | Dong, Yanhui (Offshore Oil/Gas Research Center, China University of Petroleum)
Two wells have been designed and completed using a combination of monitoring, isolation and injection control equipment to provide an understanding of injection behavior in extended-reach laterals and possible matrix bypass events (MBE) in the Nikaitchug field in Northern Alaska. These lower completion designs also provided a means to evenly distribute injection along the length of the lateral section as well as a means of mitigation and control of water if necessary.
In order to facilitate direct injection, a specifically formulated breaker system was developed to provide a delay to allow spotting in the openhole horizontal prior to running the liner and lower completion injection control assemblies. The ability to place the breaker system after drilling the horizontal mitigated risk associated with temporary flowback when inflow control devices were installed. Both post intervention and flow back were not desired.
The breaker system was formulated to provide a delay and allow the liner and injection control assembly to be installed before degradation of the residual filtercake caused uncontrollable losses thus allowing the completion phase to proceed as planned. The filtercake was deposited by a reversible invert reservoir drill-in fluid system used to drill the horizontal sections. The breaker system was unique in that it was blended as an invert emulsion and consisting of an oil continuous phase and an aqueous discontinuous phase that included a glycol acid precursor. An oil-based system was desired to reduce friction thus facilitating the installation of the lower completion hardware for these extended-reach wells.
This paper discusses the upfront assessment process, the reversible invert drill-in fluid system, the chemistry and subsequent optimization of the breaker system to achieve the drilling and completion objectives. In addition, the actual field results and lessons learned will be discussed.
Technical Leaders Interview - Neeraj Gupta of the Battelle Memorial Institute and Nigel Jenvey of Maersk Oil and Gas comment on technology applications for carbon emission control and enhanced oil recovery.
Carbon capture and storage - No abstract available.
This paper presents the alternatives available and assessment of floating platforms, stationkeeping and riser systems based on studies undertaken for Arctic fields. The industry experience with floating units for both drilling and production operations in the offshore areas subjected to ice features are discussed. The salient aspects of these systems are discussed considering the general characteristics of selected basins.
The Arctic fields developed so far are in water depths up to 125 m and have used the Gravity Based Structures and detachable FPSOs, besides other systems such as jacket platforms and islands used in shallower water. There is significant industry interest in the development of Arctic and Sub-Arctic fields in water depths beyond commercial viability of bottom founded designs. The water depths in some North American and offshore Greenland Basins are up to 2,800 m. The development of fields in deeper water would require use and adaptation of floating units and subsea systems, which have been used in many deepwater basins. However, their use in deepwater Arctic would add significant challenges from harsh weather, severe ice features (pack ice, icebergs), lack of infrastructure, remoteness, and reduced accessibility.
The floating unit designs, alternatives for sub-systems, and subsea solutions and technologies are enabling development of Arctic fields offshore Norway and Russia, such as Goliat and Shtokman in up to 350 m water depth. Floating units provide flexibility in field development and ability to detach and move the unit from the path of significant ice loading events and icebergs. These features enable improve their technical and commercial feasibility by reducing load effects and risks.
Challenges in Arctic
The development of hydrocarbon fields offshore Arctic and Sub-Arctic in the North, have gained significant importance due to potential for very large reservoirs increasing their commercial viability. Some of the important leasing areas in the Arctic or Sub-Arctic offshore identified in Fig. 1 are in deepwater and ultra-deepwater: Barent Sea, offshore Norway and Russia; Orphan Basin, offshore Newfoundland; and fields offshore Greenland and Iceland. The water depths vary from 300 m to 3,000 m in these leases and several of these fields are in exploratory drilling or in the development planning stages.
Probabilistic production forecasting at Tengiz is largely driven by reservoir uncertainty. Reservoir uncertainty is most effectively synthesized and quantified through simulation modeling. Early in the construction of a new Tengiz dynamic model, fundamental reservoir uncertainties were identified and evaluated. This allowed for model ‘building blocks' to be developed with different characterizations to encompass key uncertainties.
Key uncertainties, which can significantly impact future production under primary depletion and sour gas injection, have been described. These include typical uncertainties such as porosity, irreducible water saturation, hydrocarbon fluid properties, oil-water contact levels, rock compressibility, geologic baffles, and relative permeability. Unique uncertainties specific to Tengiz include geometry and density of the natural fractures, and reservoir heterogeneity.
Considerable production history and a large reservoir surveillance database provided input for rigorously characterizing and subsequently validating the range of each uncertainty. After ranges were established, appropriate model realizations were created. A wide range of reservoir models were obtained by selecting combinations of high/mid/low realizations for each uncertainty. Using experimental design (ED), reservoir simulations were conducted to test uncertainty ranges against field history. A quantitative history match and statistical analysis were developed to objectively judge the appropriateness of uncertainty values.
Uncertainties with the largest overall impact on the history match are: fracture density, platform horizontal permeability, compressibility, and platform heterogeneity.
This case study demonstrates how analysis of reservoir uncertainties can be: (1) captured in static and dynamic reservoir models and (2) validated through ED and quantitative history matching. This study employs state-of-the-art technologies to evaluate model uncertainties of a giant carbonate reservoir undergoing both depletion and miscible gas drives. The range of reservoir models subsequently developed will be of great value in creating robust probabilistic reservoir forecasts to optimize field operation and future development.
This paper discussed on the Execution and Contracting plan in Developing and Executing Malaysia's Deepwater Project, which mostly are considered mega projects for PETRONAS. Currently there are various Deepwater Projects ongoing in Malaysia, operated by various PSC Contractor and as the Host Authority, PETRONAS, through PMU, oversees the overall development.
- Many projects utilize different technology.
- The scope of detail design, fabrication, procurement, installation and commissioning is complex as it is being executed by various parties.
Several key processes have been implemented in addressing the challenges faced. The processes include Interface management, Capability Development program, Schedule and Cost control. The process applied is described further in this paper.
Results or Conclusion
Best approach in handling mega projects whilst ensuring that all project's objective is meet and PETRONAS aspiration to be the deepwater hub for the region will be discussed in the result and conclusion portion.
Petroliam Nasional Berhad or known as PETRONAS is Malaysia's National Oil Company (NOC) and since its establishment on 17th August 1974, it has become the manager and regulator of the petroleum resources in Malaysia. Currently PETRONAS has expanded to become a fully integrated oil and gas multinational corporation with ventures spread to more than 30 countries. PETRONAS through its Petroleum Management Unit (PMU) has regulates the E&P activities through Production Sharing Contract (PSC) in which any international oil companies that are interested to develop oil or gas field in Malaysia is required to adhere to the term and condition specified in the PSC agreement prior to commencing with any exploration and development of the awarded block. To date more than 70 PSCs has been awarded to various international oil companies covering the blocks in Malaysian water. These international oil companies will be referred as PSC Contractors in this paper.
2.1 Deepwater Field Definition
Globally, definition for deepwater field depth is yet to be established because the boundary differentiating deepwater and shallow water keep evolving as more and more technologies being developed. The United States Mineral Management Service (MMS) defines deepwater field depth from 300m to 1520m (1000 feet - 5000ft) and any depth beyond 1520m (5000ft) is considered as ultradeepwater field. In Malaysia, the depth to classify the field as deepwater range from 200m to 1200m and beyond that is considered as ultradeepwater. As for the rest of the areas, the boundary for the deepwater ranges from 200m to 1600m as described in the table below.
The Woollybutt Oil Field was discovered in 1997 and further appraisal drilling delineated two separate oil accumulations in the Early Cretaceous Barrow Group Sandstone; the Woollybutt North and South Fields. The Woollybutt North Field came on production in April 2003 with an expected field life of three years. Subsequent review and development drilling in 2005 extended the Woollybutt North Field life to 2008. The tie back of the Woollybutt South Field in 2008, previously thought to be an uneconomic area, has again increased total field life expectancy and consequently increased the expected ultimate recovery for the field.
Issues with the unknown level of productivity of the poorer quality basal Mardie Greensand reservoir and the seismic velocity gradients across the field, generated a large uncertainty in both well productivity and structural closure of the field.
A review was undertaken which integrated geophysical, geological and reservoir engineering expertise. This review resulted in the revision of the Woollybutt geological model and the development of the Woollybutt South Field. An additional benefit was to also extend the production life of the Woollybutt North Field.
This paper describes the original geophysical and geological model and demonstrates how simulation history match feedback can influence the mapping of the structural closure of the field. This result was integrated with a wireline mini drill-stem test within the poorer quality reservoir sandstone and led to the development of a new geological model. Subsequently the decision was made to develop the Woollybutt South Field, which is dominated by this poorer reservoir; the basal Mardie Greensand.