Meng, Xiangjuan (PetroChina Tarim Oilfield Company) | Pan, Zhaocai (PetroChina Tarim Oilfield Company) | Chen, Defei (PetroChina Tarim Oilfield Company) | Su, Zhou (PetroChina Tarim Oilfield Company) | Wang, Peng (PetroChina Tarim Oilfield Company) | Liu, Ju (PetroChina Tarim Oilfield Company) | Shen, Jianxin (PetroChina Tarim Oilfield Company) | Cao, Xianping (PetroChina Tarim Oilfield Company) | Bai, Xiaofei (PetroChina Tarim Oilfield Company)
Casing failure probability is high in Tarim Oilfield, due to high pressure high temperature and high sality operational environment, near 6% of total wells were damaged during their production life, which has serious impacts on the development well pattern, resulting in unbalanced injection-production. Based on the analysis of the situation and distribution of casing damage in the Tarim Oilfield, which located in northwest of China, was discovered in 1989, Its production formation has unwanted characteristics of high temperature (150 C) and high salinity (250000mg/L), in order to treatment the casing damage wells, a new type of chemical plugging agent named LTTD was synthesized on the basis of LTSD and its resistance to acid, temperature and salinity were carried out by experiments to evaluate the property of new chemical plugging agent. The plugging strength of LTTD and G-grade cement solidified body in different periods was studied by simulating the actual conditions of Tarim Oilfield, the mechanical properties of adhesive interface between LTTD and G-grade cement under dynamic condition were evaluated and microscopic observation of adhesive interface under dynamic condition were carried out. The experimental results show that the new plugging agent is characterized by marked improvement of performance and the enhanced resistance to acid, high salinity and high temperature conditions, moreover the formation of "the interpenetrating network structure" with high pressure bearing capacity in short time. In the actual condition of Tarim Oilfield, the plugging strength of LTTD plugging increase with the increase of temperature, which is higher than the strength of G-grade cement, during dynamic process, LTTD plugging is superior to G-grade cement in less amount of dissolution of calcium in hydration process and in better anti-channeling performance. Microscopic observation shows that both the inner and the bonding surfaces of the LTTD blocking agent have compact microstructure, which could effectively avoid the excessive formation of hydration product on bonding interface, and could produce hydration products against erosion, with strong self-healing ability and improve plugging quality. Field tests show that not only repair casing damage successfully, but also promote the oil production. Therefore, the development of new plugging agent can improve the ultimate recovery of Tarim oilfield.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
This paper discusses the successful, fully integrated, 3D Earth modeling (EM) and dynamic reservoir simulation of the Hollin Formation in the Lago Agrio Field within an operator's first producer field in Ecuador. Early feedback of reservoir heterogeneity helped in understanding key reservoir issues and developing the methods undertaken to solve various problems. The implementation of cutting-edge reservoir-modeling techniques contributed to improving production rates and enhancing recovery. Lago Agrio has features of a mature field: more than 43 years of production history, 75% of extracted official reserves P1 and P2 (quantified by the operating company), and a declination from plateau production of 31%, along with a steady decline of the field. New drilling and the workover of existing wells during the reservoir productive life have not been able to increase production.
In the Andes, surrounded by mountains such as Cotopaxi, Illinizas, and Pichincha, is Quito, the capital of Ecuador. Despite its altitude of 9,186 ft above sea level, the weather between 10 C to 27 C lets people enjoy Quito all year long. The Spanish founded Quito in 1534, and where Inca's temples were before, they built churches and monasteries that today make up the Quito historic center, which is declared as a First Cultural Heritage Site of Mankind in 1978 by UNESCO, being the best-preserved historic center in Latin America. But Quito is more than buildings and parks: Quito is its people. And Ecuadorians are friendly and kind people always willing to help with advice and a smile.
Ramirez Carabali, Nelson Xavier (Halliburton) | Fuerte Beltran, Jeimmy Elizabeth (Halliburton) | Mata, Jose Gregorio (Halliburton) | Castillo, Rommel (Petroamazonas EP) | Cuenca, Dario (Petroamazonas EP)
This paper compares production results and the evaluation of conventional logs versus advanced logs as nuclear magnetic resonance (NMR) in a mature field, discusses vertical reservoir heterogeneity and different flow units in apparent homogeneous reservoirs, and identifies bypass reserves oil resulting from poor sweep efficiency. A petrophysical evaluation was performed using conventional and advanced logs. Comparing the results with dynamic production logs demonstrated that the NMR evaluation was more accurate than conventional log evaluation in identifying different flow units. Traditional interpretations with conventional tools did not identify the water entry problems caused by different flow unit systems, which resulted in production sweep effects from nearby wells. NMR identified this problem, the reservoir quality, and the vertical heterogeneity and its effect on water entry. It was determined that a uniform sweep did not exist from the bottom to the top of the reservoir; thus, the aquifer water entry depended exclusively on reservoir quality related to flow unit characterization and capacity, as permeability and seal distributions are locally developed.
The continuous evaluation of electric submersible pumps (ESP) performance and its integration within the energy management system in the operation of Blocks 16 & 67 of Ecuador allowed to develop a specific procedure to assess the efficiency of ESPs in order to identify energy improvement opportunities. This procedure is summarized with the Significance Matrix, a tool that integrates ESP's field data such as production history and electrical measurements to estimate hydraulic and electrical power requirements, and a specific method for efficiency evaluation. The result of the Significance Matrix is the categorization of each ESP system as significant or nosignificant use of energy. The significant uses of energy are further analyzed to design an action plan that is prioritized through technical and economic assessment. The comparison between the Significance Matrix of December 2014 and November 2017 showed that the optimization of eight (8) ESP systems resulted in an average reduction of 49 BDPD in fuel consumption that can be translated to a decrease in greenhouse gases emission of 20 tCO2 per day.
Estimating reserves is one of the most important steps in the oil industry by which the hydrocarbon volumes in a field are evaluated economically. The principal objective of this work was to present an analysis of the main differences in the estimation of OOIP for assessing the reserves in the block II of Urdaneta-01 heavy oil reservoir, using both the rock typing approach of this study and the traditional open hole log analysis with standard specifications of the area, as well as identifying the impact into the outcomes of the following parameters, net pay thickness, porosity and water saturation through a full 3D Geomodel processing and calculations.
The complete petrophysical model for the rock type approach follows all mayor steps in computing rock type percentages, modified lorenz plot, stratigraphic modified lorenz plot, flow unit and rock properties per each well from laboratory measurements of key reservoir parameters such as porosity and permeability, while the standard open hole log analysis is set with official parameters values from the study area. For both methods a 3D-Grid model of block II is created with specific settings in order to see the spatial distribution of rock properties and oil volume reckoning.
The final result shows a contrast between the two models generated, that is, the total hydrocarbon volume is higher in the case of rock typing evaluation, there is a difference between the two models of 302 MM SBT. In addition, in terms of rock properties, the storage capacity and water saturation are the most sensitive parameters at the moment of calculations, at least 4 % difference between average porosity from log-based traditional techniques and the rock classification approach. A reliable OOIP was obtained when water saturation distribution can be controlled.
The study started with the review of pressure transient analysis (PTA), resulting in updated values of permeability, skin and reservoir pressure, then conventional and special well logs were revisited to get a consistent approach of reservoir pay intervals. The characterization of formation damage mechanism was performed to confirm and complement the results. Strategic execution of the hydraulic fracturing workovers was implemented for fast track execution and to maximize results. The rigorous and fundamentals-based review showed that additional production potential, on most of the wells in the field, could be achieved by hydraulic fracturing due to the high skin values and the deep penetration nature of the damaged zone. The interventions schedule of producing and nonproducing wells resulted in short deferred production times. All planned jobs were designed with the goal of reaching the maximum production defined by hydraulic fracturing and complete nodal analysis. Most fracturing jobs resulted in folds of increase, FOI, from 2 to 13.
Fun-Sang, B. (Schlumberger) | Arévalo, J. (Schlumberger) | Zamora, P. (Schlumberger) | Grijalva, R. (Schlumberger) | López, Y. (Schlumberger) | Fraga, R. (Schlumberger) | Pineiros, S. (Petroamazonas EP) | Mendoza, A. (Petroamazonas EP) | Carrión, J. (Petroamazonas EP) | Jiménez, T. (EPN)
The Auca field, located in the Amazonian region of Ecuador, started production in 1970, reaching a peak of 75,000 BOPD in March 2015. By the end of 2015, production declined to 65,000 BOPD due to water cut increase, reservoir pressure loss, and progressive formation damage. In January 2016, Petroamazonas EP (PAM) and Schlumberger (SLB) initiated the Shaya Project with the objective of increasing production and reserves through infill drilling, secondary recovery, and well interventions. The Auca field produces from the Hollín Formation and the Napo U and T sandstones. The latter two normally suffer from pressure depletion due to weak aquifer support, whereas the Hollín formation maintains reservoir pressure due a strong aquifer acting from the bottom. In general, formation damage in the Auca field is caused during drilling and pulling activities due to invasion of drilling or control fluids, but it also happens naturally in form of scale precipitation which has been physically proved, and possibly fines migration which remains a theory yet to be verified. Several workflows, procedures, and research on the nature of the damage have been put in place to resolve the production loss and decline issues associated with the varios potential causes. The selection of the most appropriate damage-removal technique depends on the reservoir and fluid properties, reservoir architecture, production behavior, water diagnosics, well intervention history, well geometry, artificial lift system, and, most importantly, the nature of the formation damage. From the reservoir and production engineering perspective, understanding formation damage and identifying its root cause is a key for designing the appropriate solution. After 18 months of intensive activity with drilling and workover operations, the production of the Auca field is close to 72,000 BOPD. If the operator had decided to stop activities, the production baseline would be at 35,000 BOPD. This means that, at present, the project has contributed a net incremental of 37,000 BOPD, of which approximately 30% corresponds to damage-removal jobs. This is a case study on one of the largest producing oilfields in the Oriente Basin that shows the typical productivity issues to deal with siliciclastic reservoirs and provides an example of how to select the most appropriate damage-removal techniques.