This work describes a 3D approach that was used to reduce drilling risks and unscheduled events in Palo Azul field. The field is in the Oriente foreland basin (Figure 1), contiguous to the Ecuadorian Andean foothills. A portion of the field presented an unexpected igneous intrusion (laccolite) just above the reservoir formation. The 3D analysis combined 3D seismic information with the 3D structural and geological model to generate a 3D geomechanical model. The mechanical earth model (MEM), relied on onsite real-time monitoring, was used to support drilling decisions, providing predictions of well trajectory, casing points, and mud window. The 3D velocity/amplitude cube, derived from one portion of the 3D seismic program, was used as the base to construct the MEM. To capture the uncommon structural characteristics associated with the complex geological structure, an innovative methodology was developed. Steps included special reprocessing of sequences of the seismic data; structural model reinterpretation; 3D seismic velocity analysis; population of the rock properties in the 3D domain (Geostatistical approach); integration with wireline logs; core measurements analysis; and drilling history review of the offset wells. The real-time geomechanics support allowed making important decisions in time when unplanned events occurred while drilling. This new methodology created a systematic approach to well planning that reduces drilling risks in the development of a complex area. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time. A sensitivity analysis of different well trajectories across fractured zones was performed. Wellbore stability forecasts were compared with reference to the 3D model developed. The results obtained contribute to a better understanding of the mechanics of stress development around a magmatic intrusion and a faulted/folded zone. The methodology developed allows better insight into the parameters that must be included in the 3D MEM creation and wellbore stability forecast for similar environments. This method also serves as a good basis for further development, such as sanding studies, completion design optimization, reservoir studies, and uncertainty analysis. Introduction Palo Azul field, operated by Petrobras Energia Ecuador, is a development field located in the Oriente Basin. This field is being developed by three different well pads.During the planning stage of well PA-14, Petrobras Energia identified the risks in this area, based on an unsuccessful experience during drilling one well into this dome structure formed by igneous intrusion. The Geomechanics group from Schlumberger, integrated with the Drilling and G&G group from Petrobras Energia, developed a 3D solution that minimizes the drilling risks in this area. RockSolid[TM], wellbore stability software[1], was used to construc a 1D MEM (Mechanical Earth Model) [2], which was calibrated through drilling events analysis, image logs, and core-strength data from multistage triaxial test. The mechanical earth model is a numerical representation of the state of stress and rock mechanical properties for a specific stratigraphic section in a field or basin. Petrel[TM], 3D geological modeling software[3], used this information in conjuction with an acquired vertical seismic profile (VSP) and 3D seismic, to build the 3D-MEM. This new model uses a basic petrophysical and sonic well log curves to determine the mechanical properties. Using the available geostatistical tools, these mechanical rock properties were populated across the field. The geological and structural model previously defined in Petrel[TM] was taken into account followed by the use of the 3D seismic velocity cube. The advantage of this method is that it can handle several parameters using a 3D approach to design the optimal well trajectory.In this work, the sensitivity of well trajectory across the fracture zones, mainly limestone layers, were investigated. The sensitivity analysis is performed for several well trajectories; following velocity anomalies related to these fracture zones in combination with structural features.

This paper shows how a geomechanical model helped to reduce risks and non-productive time experienced in the past in a field in the Neuquén Basin (Argentina) operated by Petrobras EnergÍa S.A. (PESA). Tight hole and stuck pipe were common problems in spite of the tight and strong formations in the field. Gas inflows were also experienced when drilling through the overpressured formations. All these events made the decision of building a geomechanical model for the field in order to optimize the drilling time. Pore pressure, stresses and mechanical rock properties were constrained based on good quality data set from eight wells. After that, the geomechanical model was validated using the caliper data and drilling experience. A key part of the model building was the estimation of pore pressure using wireline logs, gas inflows during the drilling, production data and minifrac tests. Overpressured zones were identified improving the design of the casing depths for new wells, minimizing the risks of kicks while maintaining the wellbore stability. Based on the remaining uncertainties of the model, an update phase was recommended to be done after the collection of new data such as image logs in the well to be drilled. After drilling the new well using the recommendations of the geomechanical model, the drilling experience showed that the well was drilled almost without non-productive time (NPT) through the same formations where in the past tight holes and stuck pipes were experienced. A good image data collected in the drilled well showed that the breakouts stayed below the catastrophic limit, confirming that the mud weight was correctly recommended in the phase 1, maintaining the wellbore stability without reducing the ROP. Also, the observed breakout orientation and width confirmed the orientation and magnitude of the maximum horizontal stress constrained in the phase 1. Introduction The Neuquén Basin is an important province for gas exploitation in Argentina (Figure 1) where Petrobras EnergÍa S.A. (PESA) has been operating a field in which most of wells drilled in the past experienced considerable non-productive time (NPT) due to tight holes and stuck pipe problems in spite of the strong formations in the lithological column. Gas inflows were also detected indicating an overpressured zone that should be well identified in order to reduce the risks of kicks and well control problems. Because of that drilling experience, PESA made the decision of building a geomechanical model for the field to optimize the drilling time, by obtaining a good rate of penetration (ROP) while maintaining the wellbore stability, and reducing the risk of kicks. In order to build the geomechanical model, a data audit was carried out over eight wells covering a representative area of the field. The data used included: regular wireline logs (gamma ray, density, resistivity, sonic, caliper), daily drilling reports, image data, production data, pore pressure measurements and also minifracs. By using all the available data and applying the best geomechanical modeling techniques the stress field, pore pressure and rock properties were constrained. In addition, in order to reduce the remaining uncertainties, a specific data acquisition was recommended for the designed well. In the wellbore stability analysis the potential risks of kicks and instability problems were evaluated in order to optimize the casing depths and keep a good ROP. The designed well showed a significant improvement in the reduction of the NPT related to wellbore instability problems, while the ROP was maintained at very good levels. Following the recommendations for data acquisition a good set of image data was obtained in the well, which confirmed the direction and magnitude of the maximum horizontal stress and also that the mud weight was effectively designed as the average breakout width stayed below the catastrophic limit.

The An Aike-Barda Las Vegas field, located in the Austral basin 80 km west of Rio Gallegos, Argentina, represents an important discovery in basin development in recent years. The field is an important Springhill formation gas reservoir at an approximate depth of 3100 m and with static pressure of 4400 psi. Gas rates are up to 1 MM m3/d/well. Drilling appraisal and development wells requires the optimization of every operation involved. In this context, improvements in well construction and completion methodology are important contributions. Original well design included 13 3/8-in. surface and 9 5/8-in. and 7-in. casings, with a permanent packer and 4 1/2-in. tubing. The new monobore well design reduces the diameter of each drilled section, narrowing to a 4 1/2-in. monobore installation through the pay zone. The rigless completion includes coiled tubing. Before adopting the design change, potential risk analyses were made to account for the possibility of future reentries and for simultaneous development of a second target (Magallanes formation) at 1700 m. The final well design model showed a cost savings of 30 percent, a sizeable impact on the economics of this project. History The Springhill formation gas reservoir at a depth of 3100 m produces up to 1 MM m3/d/well and has a static pressure of 4400 psi. Fig. 1 shows the stratigraphic sequence of the An Aike field. Above the Springhill is another productive formation called Magallanes. Magallanes is an oil and gas reservoir with a static pressure of 2500 psi at 1700 m depth. So far, this formation has not been developed. The first wells of the An Aike field were drilled to 600 m with 13 3/8-in. surface pipe; 2000 m of 95/8-in. intermediate pipe, to case the Magallanes formation; and a 7-in. production liner in 8 1/2-in. hole, to total depth, through the Springhill gas-producing formation (Fig. 2). Drilling Several alternative designs were considered in order to reduce cost, with special focus on the completion requirements. The analysis of possible wellbore size reduction led to the design of the AA-6 well, with 30% savings as shown in Fig. 8. This well was cased to 600 m of 9 5/8-in. surface pipe; 2000 m of 7-in. intermediate pipe; and a 4 1/2-in. production liner in 6 1/8-in. hole at the total depth, through the Springhill gas-producing formation. This reduced diameter well configuration schematic is shown in Fig. 3. The time/depth curves of these wells before and after the changes (Fig. 4) show that rig time and costs were significantly reduced with the new reduced diameter design (Fig. 5). Down to 2000 m, the on bottom rotating time was reduced by 3.3 days, by drilling an 8 1/2-in. versus 12 1/2-in. borehole (Fig. 6). Spud to the total depth, rig time was reduced by 9 days (Fig. 7). Rig time had the greatest impact on the total cost reduction, as shown in Fig. 5. Reduced requirements for mud and tubular goods were also significant factors in containing overall well costs with the reduced diameter design. The AA-3 and AA-5 wells were drilled with the first design (Fig. 2), AA-6 was drilled as shown in Fig. 3, and the AA-8 and AA-9 wells were drilled with the new design shown in Fig. 10.

The Ishpingo-4 and Ishpingo-3 wells were drilled by Petroecuador - Ecuador's state-owned company - in the ITT (Ishpingo-Tiputini-Tambococha) field. This field is located in the Yasuní National Park in the Ecuadorian Amazon region, which was declared a World Biosphere Reserve by UNESCO in 1989. The Ishpingo wells were drilled primarily to delineate oil reserves, and the project was managed by Petroecuador and PETROBRAS ENERGIA S.A. (PE)professionals. PE contributed recent experience gained from drilling two appraisal wells, Apaika 1x and Obe 1x, across the lease line. These wells were drilled and tested within the same natural life reserve area with similar heliborne equipment, materials and personnel. To operate in this highly sensitive area, PE and Petroecuador developed a specific Environmental Management Program (EMP) that actively involved environmental authorities and representatives from native communities. The EMP was prepared using the PE Integrated HSE Management System certified by ISO14001 and OHSAS 18001. To assess the results, audits were jointly conducted by the Ecuadorian government, the native communities and the company. In 1992, two vertical wells - Ishpingo-1 and Ishpingo-2 - were drilled in the Ishpingo field. The additional appraisal wells were planned with extended reach trajectories from existing well locations to minimize environmental impact. The logistics, drilling and testing of the two high-angle wells were operationally successful, and the geological target was reached to confirm hydrocarbon occurrence and reserve size. Ishpingo-3 set records in Ecuador as the steepest dip well drilled in a 16-in. section and the steepest dip well out of all high-angle wells drilled in that country. The high-viscosity crude oil - 12° API - as well as the high-deviation angle of the wells prevented the use of conventional testing techniques. Therefore, special methods, together with state-of-the-art directional equipment, were employed to determine both deliverability and reservoir boundaries. The effective application of these technologies, with optimum allocation of there sources and good terrestrial-fluvial-aerial logistics, resulted in a highly successful operation overall. Introduction The ITT (Ishpingo-Tiputini-Tambococha) blocks held by Petroecuador and Block31 held by PE are located in the Yasun National Park (YNP) in the EcuadorianAmazon region. This park was created by the Ecuadorian State in 1979 and wasdeclared a World Biosphere Reserve by UNESCO in 1989. YNP is the Ecuadorianprotected area exhibiting the highest degree of biodiversity, includingamphibians, reptiles, mammals, fish and invertebrates. In addition, the numberof plant species in the YNP makes it Ecuador's second most important regionwith regard to flora diversity per acre. Because of its large spatial area (Fig. 1), the YNP can host healthyand stable stocks of any species over time (1999 YNP Strategic ManagementPlan). Most of the area covered by the blocks within the park consists ofpermanently or temporarily flooded forests. Vegetation consists of primaryforest with isolated human settlements. The park temperature ranges from 24° to26°C with 77% to 88% humidity, and precipitation exceeds 12,000 mm/yr. The YNP is inhabited by Quichua and Huaorani peoples. The Huaorani make up atribal community whose origins or historical references are unknown. The Kawimeno settlement dates to 1982 when the Taparon Anameni community, later known as Garzacocha and currently as Kawimeno, was founded with the help of the Capuchinos Mission. This is the only community near the project, located on thebanks of the Yasun River, which runs SW of the confluence with the Pindoyacu River. In 1992, two vertical exploration wells - Ishpingo-1 and Ishpingo-2 - were drilled by Petroecuador to 6190 ft (1887 m) and 5980 ft (1823 m), respectively. Oil was found in the Basal Tena, U and M formations. The fields contain heavy crude oil (12° to 14° API), and the wells are temporarily abandoned.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis work describes a 3D approach that was used to reduce drilling risks and unscheduled events in Palo Azul field. The field is in the Oriente foreland basin (Figure 1), contiguous to the Ecuadorian Andean foothills. A portion of the field presented an unexpected igneous intrusion (laccolite) just above the reservoir formation. The 3D analysis combined 3D seismic information with the 3D structural and geological model to generate a 3D geomechanical model. The mechanical earth model (MEM), relied on onsite real-time monitoring, was used to support drilling decisions, providing predictions of well trajectory, casing points, and mud window.The 3D velocity/amplitude cube, derived from one portion of the 3D seismic program, was used as the base to construct the MEM. To capture the uncommon structural characteristics associated with the complex geological structure, an innovative methodology was developed. Steps included special reprocessing of sequences of the seismic data; structural model reinterpretation; 3D seismic velocity analysis; population of the rock properties in the 3D domain (Geostatistical approach); integration with wireline logs; core measurements analysis; and drilling history review of the offset wells. The real-time geomechanics support allowed making important decisions in time when unplanned events occurred while drilling.This new methodology created a systematic approach to well planning that reduces drilling risks in the development of a complex area. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time. A sensitivity analysis of different well trajectories across fractured zones was performed. Wellbore stability forecasts were compared with reference to the 3D model developed. The results obtained contribute to a better understanding of the mechanics of stress development around a magmatic intrusion and a faulted/folded zone. The methodology developed allows better insight into the parameters that must be included in the 3D MEM creation and wellbore stability forecast for similar environments. This method also serves as a good basis for further development, such as sanding studies, completion design optimization, reservoir studies, and uncertainty analysis. * EarthGM™ is a WesternGeco software; DrillMAP TM Schlumberger product