The LL-04 reservoir is located in the northeastern section of Lake Maracaibo and is part of the prolific Bolivar Coastal Field (BCF). Since its discovery in the late 1920's, this reservoir has produced over 520 MMSTB of oil from shallow (<3000 feet), unconsolidated fluvial and fluvial deltaic sandstones of the Miocene Lagunillas and La Rosa formations. Production is complicated by the heterogeneous nature of the sediments, low oil gravity (12° -19° API) and water coning and channeling. A multidisciplinary team consisting of engineers, geologists, geophysicists and petrophysicists was assembled to characterize and simulate the field. The objective of the team was to develop a reservoir management plan for the LL-04 Field that would increase daily production and ultimate recovery. Available data included 3-D seismic, openhole logs from over 600 wells, four cores and production and pressure measurements. All available data were used and honored in the interpretation process. Pressure measurements and production history were integrated with the seismic interpretation, log analysis, core descriptions, log correlations and deterministic mapping to define the reservoir compartments. Seven reservoir regions were defined. The original oil in place (OOIP) was increased by 44% as a result of this rigorous study. Also, 80 workover/recompletion candidates and 25 areas for infill drilling were identified. Introduction The mature LL04 reservoir, located along the Bolivar Coast of Lake Maracaibo, Venezuela, was discovered in 1926, and has produced over 520 MMSTB of oil as of December 2000. Producing mechanisms are natural depletion, water support from aquifer and injection, gas and LPG injection and compaction. Cyclic "huff'n'puff" steam injection has been used in 70 wells, as a stimulation mechanism. The main objective of the study was to address the numerous production problems in order to optimize the recovery of the substantial remaining reserves within the exploitable area.

The objective of this work is to present a comprehensive workflow to optimize the value of a hydrocarbon asset evaluation project under high degrees of uncertainty. This workflow is applicable to both conventional and unconventional assets. However, because of the considerable level of subsurface uncertainty and high initial costs (mainly due to drilling and hydraulic fracturing operations), unconventional resources are good examples for demonstrating the benefits of the workflow. For the case of an unconventional asset, well spacing and perforation cluster spacing are usually the decision parameters that need to be optimized to increase its value. The workflow begins with the construction of a representative base case single well gas simulation model for production history matching. Petrophysical, geological, geomechanical, stimulation, completions and production data are interpreted and analyzed together to better understand drivers that could be influencing the production. If this can be repeated with several wells in the block with sufficient production data, the process is enriched as so the level of confidence, as the range of history-matching parameters from these different wells across the block can be captured for sensitivity and uncertainty analysis. Several sets of sensitivities and uncertainty runs are then performed to get a probabilistic production profile in the presence of the most influential parameters. It is important to highlight that usually, the limited number of wells, short production histories, different dynamic behavior in neighboring blocks and the lack of necessary data to help understand well performance all contribute to the high uncertainty in predicting production. Given the high cost of drilling and hydraulic fracturing and on the other hand the high gas price in Argentina, optimizing well spacing and cluster spacing are critical parameters in the process of unconventional resource evaluation considering the high degree of uncertainty.

This paper summarizes the achievements of an alliance between Ecopetrol, S.A. and Schlumberger to revitalize the Casabe field, a mature field located in Colombia. Challenges have been multifaceted in this mature complex field. Some relate to the heterogeneous nature of the reservoirs, limited sand continuity, unfavorable mobility for the waterflooding ongoing process, associated sand production, and wells lost due to collapses. Parallel efforts on fast-track studies and field development planning (FDP) were performed. The FDP incorporates technology application such as:3D seismicNew geological modelNew correlation in detailed scaleDrilling in fresh oil areas, infill, and new structuresSelective water injectionNew waterflood design and monitoringStrong increment of water injected by pattern. From 2004 to 2008, the integrated project has increased the oil production from 5,200 BOPD to 11,900 BOPD with a reserves replacement ratio of more than 100% per year. All these factors provided extension to the life of this complex field while bringing additional financial benefits for the partners. The article presents the FDP planning methodology, that overall proved to be useful and repeatable for other fields. Introduction The Casabe field, discovered by Shell in 1941, is located in the Mid-Magdalena Valley basin and it has 1,120 wells, which have accumulated 284 MMbbl of oil as of December 2007. The productive formations, from bottom to top, are La Paz, Mugrosa, and Colorado, with depths ranging from 2,200 to 5,500 ft. The production peaked at 46,000 BOPD in 1953 and achieved a primary recovery factor of 13% under natural mechanisms. Since 1985, the field has been under waterflooding, which raised the recovery to 19.8%. Waterflooding has been a challenge due to the very heterogeneous nature of the reservoirs, sand continuity complexity, the oil viscosity, sand production and wells lost due to collapses. The location of the field is shown in Figure 1. Since 2004 Ecopetrol, S.A., and Schlumberger have made a combined effort to revitalize this mature field to increase its value through a Field Management Alliance. The Field Revitalization effort started with fast-track integrated analytical studies to prove potential in the most prolific sectors of the field, which initially led to drill 6 new producers and repair more than 20. In 4 years, these numbers have increased to 65 new wells and 180 workovers, and 60 additional wells were planned to be drilled in 2009. As new data has been collected and incorporated, different modeling approaches helped us to understand reservoir behavior and mechanisms. The field redevelopment plan embraced 3Dseismic data acquisition, selective water injection, appraisal wells and technology application, as well as facilities upgrades to handle the incremental production and injection volumes. This paper will expand on the integrated planning and implementation of this revitalization "production project."

This document presents the development and results of a study for determining the possible reasons of casing collapse in the Casabe Field, Colombia, specifically in block VI, where the phenomena occurred with more intensity. The study was requested as part of a revitalization strategy for this mature field, to maintain and improve the production performance of new and existing wells. The study consisted of different phases:Statistical and Probabilistic: firstly related to trend identification (i.e. well type, drilling date, well status and collapse localization), and secondly reliability and failure curves were created using the probabilistic Montecarlo analysis.Mechanical Integrity: casing integrity was analyzed using a software application called TDAS, by taking into account the corrosion effect and different operational and typical loads.Water flooding effects were also analyzed to take into account the stresses created by water injection on the casings at different formation levels (A or B). Figure 1 shows the four main phases that comprised the study. As a result of this study, a new well mechanical design was created and successfully applied on all new wells drilled in the Casabe field with zero collapse occurrences. Well longevity has been guaranteed, improving the economics of the field. The study gives a safety operational procedure considering a range in different parameters (tension, fluid level, corrosion, injection pressure and type of casing) that give support to critical well operations in order to mitigate casing collapse. Introduction Casabe is an old and mature field located in Yondó (Colombia), in the mid-Magdalena River Valley basin and has an extension of 25 Km2. Along the productive life of the field, well casing collapse was identified as a critical problem, as some 45% of producers exhibited collapse with different severity levels. This problem increased over time, but the causes had not been totally identified. Due to casing collapse, injection rates were reduced in an effort to reduce its occurrence rate. Consequently, the waterflooding process was underperforming. The field has eight blocks defined by normal faults. Block VI is the biggest of all in terms of reserves and presented in 2006 the highest proportion of collapsed wells, a total of 214. To produce those reserves, a re-development plan was implemented in 2006 with an intense drilling campaign. The study of the casing collapses became hence extremely necessary.

The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 2001 1). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods.T hird, we investigated the field performance under different development scenarios. Optimization results with the single-well thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO)of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommendedhere. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development. Introduction Schlumberger Data and Consulting Services (DCS), in Denver, Colorado, initiated a project for preparing the numerical 3D predictive model of theLL-04 Miocene reservoirs in Lake Maracaibo. The objectives of the reservoir performance evaluation were toprovide Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned national oil company, with an updated geologic model that could be used to select new drilling and workover candidatesprovide PDVSA with a dynamic flow model that could be used as a tool to improve ultimate recovery from a number of operating strategies, and to monitor the field performancemake recommendations that would help PDVSA maximize production, maximize oil recovery, and to determine the best operating strategy for the field. This paper describes the reservoir simulation part of the reservoir characterization and simulation project. The Reservoir The LL-04 field is located on the northeast side of Lake Maracaibo along the Bolivar Coast of Venezuela (Fig. 1). This was one of the first fields discovered in Lake Maracaibo with production dating back to 1927. Production is from shallow (2000 to 3000 ft) unconsolidated sands in the Miocene La Rosa, Lower Laguna and Lower Lagunillas formations. Because production from the field is from highly unconsolidated sands, very limited core was available. Complicating the reservoir performance is the subsidence that has occurred. This has been accounted for by using very high rock compressibility in the simulation model.