The presence of evaporite sections in prospects for oil or gas exploration is, in itself, a factor that increases the probabilities of success in the area due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipe and casing collapse have been reported by the industry when drilling through those salt layers. Historically, in the Campos Basin - Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90's, the lack of reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high drilling costs and even loss of wells.[1] This paper presents a methodology for drilling fluid and casing design and drilling strategy for drilling at great depths through thick salt layers. The numerical simulation to evaluate the creep behavior of salt rocks (halite, carnalite and taquihydryte) submitted to high differential stress and high temperature was done through the application of an in-house finite element code developed. Results obtained by the numerical simulations in prospect with 2000 meters thickness of different evaporite rocks with high creep rate was used to predict the evolution of the well closure with time for various drilling fluid and analyze several technically feasible alternatives to drilling strategy. The casing design was accomplished with several failure scenarios of cement the casing/borehole annulus through the salt, and drilling fluid in annulus to determine the nonuniform loading and timing of salt loading on well casings deformation or ovalization. The casing was design to be capable of supporting high creep rate of carnalite and taquihydryte. Introduction The Santos Basin, offshore southeast Brazil, is one of the Brazilian basins that is receiving considerably industry attention nowadays. Active drilling in the this area in recent years has not yet yielded discoveries comparable in size to fields in Campos Basin, the most prolific oil provinces in Brazil (Fig. 1). However, due to its size and for being relative under explored, it continue to attract interest.[2] The object of this study is planning an exploratory deepwater well (WD = 2140 m) to a depth of 6000 meters TVD in Santos Basin. This prospect is expected to drill through almost 2000 m of salt rock - halite, carnalite and taquihydryte (Fig. 2). This is the first of a toal of four wells to be drilled up to the end of 2006. The presence of evaporite sections in prospects for oil or gas exploration is, in itself, a factor that increases the probabilities of success in the area due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipe and casing collapse have been reported by the industry when drilling through those salt layers. Before planning to drill long salt sections, a through knowledge of salt and its properties is necessary. Salt rocks belong to the group of sedimentary rocks, called evaporite, deposited by evaporation of saline water. Salt is an unusual geologic material for under sustained constant stress, significant deformation can be expected as a function of time, loading conditions and physical properties.[3] This behavior is called creep. The rate salt will creep is dependent on some parameters: temperature, differential stress and salt type are of the paramount importance.
fax 01-972-952-9435. AbstractThe presence of salt structures in prospects for oil and gas exploration is, in itself, a factor that increases the probability of success due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipes and casing collapse have been reported by the industry when drilling through those salt layers. Historically, in Campos Basin -Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90', the lack of a reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high costs and even loss of wells. In this paper we present a methodology for mud weight and casing design and also to define the drilling strategies employed for drilling through thick salt layers. The numerical simulations to evaluate the creep behavior of salt submitted to high differential stresses and high temperatures were done through the applications of an in-house finite element code developed. To calibrate the model, triaxial creep tests in salt samples were performed to evaluate and isolate reological properties to represent its creep behavior under different differential stresses and temperatures. It was verified that numerical and experimental results matched and had a fine conformity. A recent application of this methodology in a sub salt well in Campos Basin allowed us to drill the salt without a problem. Results obtained by numerical simulations were used to predict the evolution of the well closure with time for various mud weights and analyze several alternatives of casings capable of supporting salt creep. As a result, stuck pipe and casing collapse were avoided and drilling costs reduced.
The Pore Pressure is a critical point of any drilling project, once it influences the definition of the mud weight, casing setting depths, casing design, riser safety margin (RSM), etc. During the design stage of offshore and shallow water wells, safety factors (ranging normally from 0.5 to 1.0 ppg) are introduced to compensate the lack of accuracy in pore pressure evaluation. However, this may impose a limit in deepwater drilling operations. In such environment, as the water depth increases, the formations tend to show lower fracture gradients, which makes the difference between the pore pressure and the fracture gradient curves quite small, complicating the project. In this work the methods employed by Petrobras to evaluate the formation pressure are reviewed. Next, a procedure, employing statistical analysis, to evaluate the uncertainty in the pore pressure determination in the offshore portion of Campos Basin - Brazil, is presented. For that, a DST (drill stem test) and RFT (repeat formation test) database collected along the years in this area is employed. As a result, the safety factor applied over the Pore Pressure could be reduced, simplifying deepwater well projects. Introduction The Campos basin is currently the most productive of the Brazilian petroleum areas. This basin extends roughly from 15 km (9.3 mi) in land up to 3,400 m (11,155 ft) of water depth, coverings an area of about 100,000 km2 (2.47 106 acres) along the southeastern Brazil passive margin. To date, more than 30 oil fields have been discovered, including the giant fields of Marlin, Albacora and Roncador in about 2,000 m (6,562 ft) of water. As a consequence there is increasing interest in exploration in still greater water depths in this area (1). The offshore exploratory drilling is usually a high-cost and high-risk activity. One of the most significant sources of risk during drilling is associated with the unforeseen occurrence of formation pressure. Such situations can result in: stuck pipes, formation damage, well instability, kicks and eventually a blowout. Therefore, one of the most important objectives of the formation pressure evaluation is to drill a well safely and economically, without causing formations instabilities (collapse or fracture), without allowing inflow of formation fluids (water, oil or gas) and without causing damage to the reservoirs. In other words, the optimization of the drilling project depends on the correct evaluation of the geopressures. This evaluation is more critical in well design for deepwater wells. In this scenario, with the increase of the water depth, the formation tends to show lower fracture gradient (FG) due to having been compacted under low overburden gradient. Uncertainty in the PP evaluation is usually compensated by introducing a safety factor. Such factors range normally from 0.5 to 1.0 ppg, according with the uncertainty associated with the determination. That, however, imposes limits during the well design phase. The available margin for the mud weight, which must stay between FG and PP, can be very narrow complicating deepwater well projects, as it is schematically represented in Figure 1. In the next section, some important definitions related to the formation pressure evaluation will be given.
Drilling and completing either exploratory or development wells in Pre-Salt prospects present several challenges. The wells are located in very deep waters, beyond 2,000 m WD and they are also deep wells, with more than 5,000 m TVD. Pressure and temperature is normal, but contaminants such as H2S and CO2 represent an additional difficulty. Most of all, drilling through salt layers as thick as 2,000 m presents the most challenging aspect of these wells. Directional, extended reach (ERW), horizontal and multilateral wells will be evaluated for production development, but the reservoir is a carbonate horizon just below the salt, meaning that high angle navigation and multilateral joints will be located inside the salt layers. These wells measured depths will reach 8,000 m or more. The salt geo-mechanical loads on the casing and cementing will require high strength materials and high capacity rig equipment. The competency of the salt formations and, most of all, of the carbonate reservoir, totaling more than 3,000 m to be drilled, will require special BHA and bit design to increase penetration rates, thus reducing rig time. Carbonate reservoir will require production liner, perforations/slots and stimulation treatments designed to maximize production. Although these challenges could be overcome today, with existing technology, due to the current high costs scenario, well construction time and risks must be minimized. Some technology development is already underway to address these issues, but most of the gains can be materialized without new technology, by proper engineering design, risk management and learning curve acceleration. After 8 wells drilled in Pre-Salt prospects, Petrobras has already gained important know-how in these projects, but there is still a long way ahead. In the following years, well construction campaign for an Extended Well Testing (EWT) and a Pilot Production System in the Tupi Pre-Salt area, plus additional exploration wells, will provide field test opportunities for development and optimization of well engineering techniques and equipment. This paper will present the highlights of Petrobras E&P program to make the best use of these opportunities to leverage the well construction learning curve. Introduction In recent years, exploration activities in Brazil began to focus on the São Paulo Plateau, a prominent regional topographic feature in water depths ranging from 2,000 to 3,000 m. A continuous Aptian evaporitic sequence, in some points thicker than 2,000 m (Fig. 1), exists in this region, contrasting with the very thin marine section above. The reservoir section occurs just below the evaporitics and is composed by microbialite carbonates. In such a Pre-Salt section, with variable thickness, a few exploratory wells were drilled. Petrobras is now facing a challenge similar to that one encountered during the discoveries of deep-water turbiditic reservoirs in Campos Basin. Salts belong to a group of sedimentary rocks called evaporites, resulting from sea water evaporation. Submitted to a sustained constant stress, evaporites can suffer considerable deformation, in a behavior denominated " salt creeping??. Due to this characteristic, salt intrusions and domes can be found in many sedimentary basins, associated with either high pore pressure zones, or fractured zones (" rubble zones??).
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