Dina Cretáceos Field Chemical EOR: From Screening to Pilot Design

Abstract

Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Producing reservoir consist in a marine-transitional depositional environment with good sand continuity and thickness. Ecopetrol S.A operates the field. The field was discovered in 1969. Primary production peaked at 6,500 BOPD. Peripheral water injection started in 1985 reaching a maximum oil production rate of approximately 10,000 BOPD. Current recovery factor is estimated in 32% of the OOIP with water cuts of 96%. Water injection is operating under adverse mobility ratios (M > 4) due to crude oil viscosity (10.8 cp) at reservoir conditions.As a strategy to increase oil recovery an integrated study started in October 2009. Main objective of the multidisciplinary group was to evaluate different IOR/EOR technologies, select the most promising technology and identify areas of the field suitable to implement a pilot project. First phase of the study was a comprehensive evaluation of injection-production history of the field and IOR/EOR screening. Simultaneously, the team was also focused on updating the history match of the field injection-production history. The numerical model was based on a high-resolution geological model with a detailed lithological and petrophysical description. Once a reasonable history match was achieved the model was converted into a commercial platform to simulate chemical EOR processes.The analysis of injection-production history did not support strong water channeling due to the presence of thief zones. IOR/EOR screening results confirmed the feasibility of polymer-based technologies due to the adverse mobility ratios and remaining oil saturation in the reservoir. Reservoir analogs identified during the screening study, conceptual simulations and laboratory studies concluded that the injection of Colloidal Dispersion Gels (CDG) shows high potential to increase oil recoveries economically in Dina Field. A pilot area was selected ranking different options and operational constraints. Pilot project design scheduled for the last quarter of 2010 was based on a sector model of the field.This study provides guidance to effectively evaluate and implement chemical EOR technologies to revitalize mature water floods. A proper decision framing, availability of data and commitment of management and decision makers are key elements to perform EOR evaluations and implementation is short periods of time.

Comprehensive Guidelines for the Application of In-Situ Polymer Gels for Injection Well Conformance Improvement Based on Field Projects

“…20. Lantz (2010), Sandoval et al (2010), Mack and Lantz (2013), and the ICP methodology presented by and Maya et al (2014) showed in their basic decision making scheme for chemical flooding that in case of mature water floods with high recovery factors, there is low probability of success for conformance technologies and there is a need for a combination of sweep improvement and residual oil saturation reduction technologies. They pointed out that in these cases; the surfactant-based technologies (ASP/ SP) are the candidates.…”

Colloidal Dispersion Gels (CDG) to improve volumetric sweep efficiency in waterflooding processes

“…In more than 40 historic cases, operators have reported incremental recovery factors of up to 10% of the Original Oil In Place (OOIP) (Demin, Yingjie, Yan & Xuping, 2002;Chang et al, 2004;Norman, De Lucía & Turner, 2006;Sandoval et al, 2010;Castro et al, 2013). CDG technology is used to improve volumetric -neity of the reservoir and the adverse mobility ratio in have been implemented in Colombia, along with 6 pilots that are currently underway.…”

An integrated Shannon Entropy and reference ideal method for the selection of enhanced oil recovery pilot areas based on an unsupervised machine learning algorithm

“…Three methodologies have been presented in the literature for pilot area selection. The first category presents some qualitative insights regarding the pilot area, such as the necessity of using predictive reservoir simulation models [4,[7][8][9][10]. These studies do not provide any quantitative methods to select a pilot area.…”

“…For example, having remaining oil saturation in the range of 0.2-0.5 could lead to an appropriate pilot area [11]. According to other studies [7,8], high remaining oil saturation has been applied to locate pilot areas. In addition, a lower ratio of vertical to horizontal permeability and higher lateral permeability continuity have also been a basis for pilot area selection [15,16].…”