The reservoir is our primary asset - "surveillance is the maintenance strategy to enable delivery??
- You would not dream of poor maintenance delivery on plant and well integrity
- How do we minimize poor maintenance of reservoir delivery?
Surveillance is our primary tool for managing reservoir and well delivery; however, it is not always properly thought through and executed. On occasions we fail to act on the data we have, or capture lessons learned. Acting on this information is often where we stumble. Our ability to follow a plan, do, measure, learn loop is key to good execution and delivery of a surveillance programme that delivers the short term production and long term reserves recovery.
Vaziri, Hans H. (BP America) | Allam, Robert D. (BP Exploration Co. Ltd.) | Kidd, Gordon A. (BP Exploration) | Bennett, Clive L. (BP plc) | Grose, Trevor D. (BP Amoco) | Robinson, Peter A. (BP Exploration) | Malyn, Jeremy (BP plc)
Factors and mechanisms leading to sanding are described within an integrated-rock and soil-mechanics framework. While the conventional sanding models generally consider a single-mechanism for sanding, namely the critical depletion resulting in rock disaggregation, the proposed approach considers the interplay of several mechanisms that can lead to the rock breakup and sand transport. One important difference is that rock disaggregation is not seen to represent the onset of sanding, because the sand mass can offer significant resistance from frictional properties, interlocking of sand grains, and arching. The approach presented here can be used to explain why sanding in the field tends to be episodic, and how depletion, which is a major factor in rock breakup, can be highly effective in holding broken-up sand grains together and, in fact, become a sand-stabilizing agent.
The proposed approach is used in discussing sanding at several wells in two different fields. These wells have been in production for several years and show that sanding cannot be linked to just one unique mechanism (e.g., depletion). However, once all mechanisms for sanding are incorporated, a more consistent analysis can be used by completion and production engineers to make more objective and pragmatic decisions in managing sanding while maximizing production over the life of the well.
While a great deal of work has been done in the general area of sand production (Veeken et al. 1991; Weingarten and Perkins 1995; Risnes et al. 1982; Morita 1994; Sanfilippo et al. 1995, 1997; Tronvoll and Halleck 1994; Tronvoll et al. 1997; Papamichos and Malmanger 1999; Morita and Boyd 1991; Bradford and Cook 1994; Van den Hoek et al. 1996; Vardoulakis and Papanastasious 1988; Willson 1996; Morita et al. 1996), most of the approaches used for practical applications are on based on the assumption that the onset of sand production is represented by the failure of the perforation-tunnel wall, which is generally determined using the thick-wall-cylinder (TWC) strength test. Such an approach is well suited to predicting the maximum depletion in relatively competent rocks, particularly if they have brittle behavior. But what about weak-to-totally unconsolidated rocks having an almost-zero TWC strength, yet remaining stable under reasonably high drawdown (DD) and, in fact, showing an increase in stability with depletion (field examples presented later)? How should the DD strategy in terms of rate of change and magnitude be adjusted as the rock undergoes a structural change from a cemented formation to a totally disaggregated sand mass?
Strictly speaking, the conventional techniques for sanding prediction, which are based on Geertsma's (1985) equations, disclose the increase in confining pressure required to fail a perforation tunnel or the wellbore cavity. In practice, the approach provides an indication of the depletion that can be sustained before the weakest perforation tunnel undergoes a significant deformation, leading to its disaggregation (normally referred to as the critical bottomhole reservoir pressure). This single-case-solution scenario, which is not coupled with fluid flow, does not provide options to make objective assessment of the risks at different stages in the well's life and the most effective contingencies to mitigate such risks [see Vaziri et al. (2002a) for a full discussion of the past work in this area, formulations used, and some of the limitations). For the base case of no active sand control, operators would like to know, at any stage, how much sand will be produced (rate and duration) for a given production strategy (e.g., maximum DD, and rate of bean-up/shutdown frequency) and other changes in the reservoir conditions, such as water cut (WC). By better understanding the roles of multiple variables, one is enabled to choose the optimal completion method over the life of the well. For a more comprehensive discussion of these issues see Vaziri (2004).
BP's ISIS technology (Integrated Subsurface Information System) is changing the way BP manages reservoirs through the provision of multi-disciplinary analysis and visualisation of real-time integrated dynamic surveillance data, information and knowledge processes. The technology enables faster and integrated operational decision making, provides continuous real-time access to all digitally acquired sensor data in a well or on the platform, on a 24/7 basis, alerting users to production events which require their attention and can be acted upon. The tools developed by the ISIS Technology Program turn the vision of a real-time data pipeline into a reality by providing an innovative solution for remote visualization of information. The technology provides a robust environment for the transfer of data from the point of acquisition to the point of decision-making.
ISIS and the parallel facilities/operations project entitled D2D (data to desk) use common systems for real-time data management and visualisation. While these developments serve the distinct discipline needs of the subsurface and facilities/operations communities in terms of computational processes, there is a single collaborative system sharing technology of mutual benefit to all communities.
The ISIS system is being deployed across BP's operations as a key element of BP's FIELD OF THE FUTURE programme (1). Initial installation has been completed in seven operational assets across BP that has proven the capabilities and business benefit of the technology. Installation of the technology has been the catalyst for changing the way the field teams approach surveillance; these changes are being enhanced through use of adaptive change projects with the field teams which are changing the way BP operates its fields.
The use of sour service tubulars has come a long way since the sour service casing and tubing grades C90 and T95 were first standardized by the American Petroleum Institute (API)~. As the search for oil and gas reservoirs is expanding, it is becoming common practice to drill and produce from formations at depths in excess of 20,000 feet. In deep offshore wells, water depths of 10,000 feet are an every day phenomena. Significant colder seawater temperature resulting from the water depth, further promotes the deleterious attack of hydrogen. At these deeper formation depths, high formation pressures and gas compositions are encountered which require tubulars to not only have high yield strength, but also satisfactory resistance to environmental cracking by hydrogen sulfide stress cracking (SSC). This cracking phenomenon is a result of the exposure of high strength steels to aqueous hydrogen sulfide containing fluids, which induces a brittle-like failure. As the depths of drilling, completing and producing increase, even higher yield strength pipe with adequate SSC resistance is needed to sustain the higher stresses and colder temperatures encountered offshore. The casing design envelope is greatly affected by the relationship between pressure and H2S (ppm) concentration.
HYDROGEN SULFIDE STRESS CRACKING (SSC)
Considerable literature exists detailing the theories of the SSC mechanism.4,s,6,7 Hydrogen sulfide stress cracking (SSC) is defined as the fracturing of steel subjected simultaneously to aqueous corrosive hydrogen sulfide medium and a static stress less than the tensile strength of the material. It usually occurs in a brittle-like manner, resulting in catastrophic failures at stresses less than the yield strength of the material. SSC is basically a hydrogen embrittlement mechanism resulting from the formation of hydrogen ions (H +) in the presence of aqueous hydrogen sulfide (H2S). 2(H2S) +Fe + H20 - FeS + 2H + + S- + H2 (gas) + H20 Some of the hydrogen released by the reaction does not recombine to form molecular hydrogen (H2) due to the presence of the adsorbed S; but forms nascent or ionic (H +) hydrogen. These extremely small hydrogen ions (proton nucleus, stripped of its electron) are considerably smaller than H2 molecules or the metal atoms of the steel. These ions easily migrate or diffuse into the metal crystal lattice. The diffusion of ionic hydrogen can occur rapidly due to its small size and failures can result in very short periods. After migrating into the metal, the hydrogen ions recombine to form H2 molecules at impurities and discontinuities (such as dislocations) in the steel. One theory is that because the hydrogen gas molecules occupy significantly more volume than the individual hydrogen atoms, they cause extreme stress on the metal crystal. Hydrogen SSC resistance is a function of both the material and the environment. There are four major contributing factors for the sulfide stress cracking process to occur" 1 .) Absorption of a significant quantity of H + from the environment 2.) Tensile stress of sufficient magnitude 3.) Susceptible metallurgical properties of the steel 4.) Time These factors are interdependent, critical combinations of all four factors are required to initiate the cracking process. The environmental factors of pH, hydrogen concentration and temperature are also well documented.s, 6,7,8 In general the SSC resistance of steel increases with the presence of CO2 10 at higher temperatures, at higher pH values (less acidic) and at lower H:S concentrations. There are many material factors that affect the SSC resistance and these will be further elaborated on in this paper.
Evans, Tim (BP Exploration Operating Co. Ltd.) | Bennett, Howard (BP Exploration Operating Co. Ltd.) | Sun, Yuhua (BP Exploration Operating Co. Ltd.;) | Alvarez, Jesus (BP Exploration Operating Co. Ltd.;) | Babaian-Kibala, Elizabeth (BP Exploration Operating Co. Ltd.) | Martin, John W. (BP Amoco)
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required.
To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements.
This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed.