La Salina Field, on the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, or IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina IFL was to evaluate the alkaline-surfactantpolymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium-gravity crude oil (25°API) from the LL-03/Phase III Miocene reservoir at 915 m (3,000 ft). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, phase behavior, interfacial tension between crude oil and ASP solution, chemical retention by the porous media, and physical simulation with reservoir core samples. The laboratory design involved 23 commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000-fold were observed for a variety of ASP solutions. Type II-and Type III phase behaviors were observed. Linear coreflood results indicate that high-molecular-weight, partially hydrolyzed polyacrylamide polymers can be injected into La Salina sand. Radial sandpack floods produced an average oil recovery of 45.6% original oil in place (OOIP) with water injection. Injection of 30% pore volume of ASP solution, followed by 30% pore volume of polymer drive solution, produced (on average) an additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task because this will be the first offshore application of the ASP technology in the world. The initial decision for the plant design was to use an existing platform instead of a barge for the construction of facilities. As a result, critical parameters such as treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered. Preparation and transport of a phase-stable ASP solution through the injection lines and into the reservoir are crucial. Designed chemical concentrations and physical characteristics must be maintained.

Single well chemical tracer tests (SWCT) were carried out at the VLA-1325 well located in Lagomar, C4 reservoir, Lake Maracaibo, Venezuela, to measure residual oil saturation in zone C4-U3 before and after an ASP injection, in order to determine the swept efficiency of a custom made blend. The tests included: Phase I, measurement of residual oil saturation to water (SorW) of the pay zone, previous to an ASP application and after waterflooding procedure; Phase II, application of an ASP blend, specially designed for the aforementioned zone; and Phase III, second measurement of residual oil saturation to ASP (SorASP) after ASP application. The results show that prior to the ASP injection, the residual oil saturation at the VLA-1325 was (31 ± 3)%. This saturation measurement represents pore space in a 6.7 m (22 ft) thickness portion (1,842.4 – 1,849.1 m; 6,048 – 6,070 ft) of the C4-U3 zone from the well bore to a radial position of about 3.04 m (10 ft). A few days after this initial residual saturation, measurement was completed. A 0.35 porous volume, Vp, (1,750 bbl) ASP injection was carried out in the same 6.7 m (22 ft) completion of the C4-U3 zone. This ASP mixture was followed by 0.15 Vp (750 bbl) polymer drive solution, and a 1.2 Vp (6,000 bbl) of fresh water to push the ASP mixture and any mobilized oil about 15.8 m (52 ft) away from the test well-bore. After ASP treatment, the residual oil saturation measurement was repeated in the same pore space as the initial SWCT test investigated. This post-ASP flood SWCT test showed that the residual oil saturation in this pore space had been reduced to (16±3)%. This reduction in the SorW represents (48±1)% mobilized oil by the chemical treatment. The reported Sor measurements represent the average Sor s for the sub-zones penetrated by the tracer fluids during the test. The field data recorded during the test are presented, and compared with best-fitting simulation model results. Introduction The alkaline-surfactant-polymer technology has been widely applied in many reservoirs in order to reduce waterflood residual oil saturation. The technology combines, sinergistically, the interfacial tension reducing effect of added surfactants and those produced in the acidic crude oil by alkaline reaction of organic acids, with the mobility control improvement obtained adding a water soluble polymer. Many papers have been recently published regarding application and design of ASP formulations [1–6]. The Lagomar "Field Integrated Laboratory" (FIL, i.e. LIC after its initials in Spanish), was conceived to evaluate some IOR technologies [2,7]. It was one of the main goals of such a FIL, the design and application of a chemical tracer test using a single well in order to determine the efficiency of an ASP custom made formulation [2] for the VLA-6/9/21 area of the C4 reservoir at Lagomar FIL. This combined SWCT-ASP-SWCT is the next step in the evaluation process before a potential massive application [8–11]. Geology of the Pilot Area The VLA-6/9/21 area is located in northern Lake Maracaibo (Figure 1). It covers an area of 65 km2 (16,056 acres). The reservoir C4 is one of the many composing the Eocene Misoa Formation. The pilot area selected for the FIL is 10 km2 (2,470 acres) in extention and is located at the southern part of the VLA-6/9/21. It is confined between two major sealing faults to the South and West respectively and an oil-water contact to the East. To the North, there is an arbitrary limit. The member C4 contains light crude oil 34.6 °API, a pressure of 6,894 kPa (1,000 psi), and thickness of 137.1 m (450 ft). The C4 member, Shalow Eocene, is divided in five submembers. These are named: C4-U1, C4-U2, C4-U3, C4-M, and C4-L. Submember C4-U3 has a thickness between 12.1–30.5 m (40–100 ft). Its porosity ranges from 17–26% with an average value of 21%. Geology of the Pilot Area. The VLA-6/9/21 area is located in northern Lake Maracaibo (Figure 1). It covers an area of 65 km2 (16,056 acres). The reservoir C4 is one of the many composing the Eocene Misoa Formation. The pilot area selected for the FIL is 10 km2 (2,470 acres) in extention and is located at the southern part of the VLA-6/9/21. It is confined between two major sealing faults to the South and West respectively and an oil-water contact to the East. To the North, there is an arbitrary limit. The member C4 contains light crude oil 34.6 °API, a pressure of 6,894 kPa (1,000 psi), and thickness of 137.1 m (450 ft). The C4 member, Shalow Eocene, is divided in five submembers. These are named: C4-U1, C4-U2, C4-U3, C4-M, and C4-L. Submember C4-U3 has a thickness between 12.1–30.5 m (40–100 ft). Its porosity ranges from 17–26% with an average value of 21%.

It is widely accepted that comprehensive data acquisition programs are necessary for WAG management and pilot project interpretations. Common data acquisition methods used to monitore WAG processes are frequently analysis of separator testing, fluid composition, production/injection rates, pressures injection surveys, gas-oil ratios (GOR) and saturation logging. Chemical tracers have been used as a tool for monitoring water and gas injection, whereas for WAG process no experience in a field has been reported in Latinamerica. At the Lagocinco field, C2/VLE-305 reservoir (located in Maracaibo Lake basin) a WAG pilot project is currently being developed, using a chemical tracers program with Perfluorocarbon and fluorinated Benzoic acids. Five chemical tracers have been injected in both phases (water and gas) during WAG test as a surveillance tool for the process. The aim to inject gas and water tracers was related to use breakthrough time and tracer production/injection history to get a better understanding of dynamic reservoir behavior and to support and upgrade the reservoir model. This paper briefly describes the monitoring process achieved in Lagocinco pilot project, and some results of this monitoring in relation to the WAG process. The result of the first water tracer test has indicated early breakthrough in four wells of the pilot project. One of the wells has increased oil production rate and three of them have maintained oil production rate and have decreased water cut and GOR as consequence of WAG process. The rest of the wells do not show a clear trend in tracer production, confirming heterogeneities in the pilot area. Zones not drained were identified and connection between the injector well and producer were characterized. The results of the first gas tracer have shown different distributions and velocities between gas and water. Finally, the second water tracer breakthrough was observed 3.3 months after its injection, just in one well, declaring that water distribution or path has changed as a consequence of WAG process. Introduction WAG injection processes have become an important IOR technique around the world [1], and have been focus of interest in recent years in Venezuela. This drained strategy is mainly planned to deal with the mayor concerns in Venezuelan oil fields: optimizing natural gas resources and increasing oil recovery factors [2]. Among several candidates, the VLE area was selected to evaluate an immiscible WAG process as representative of large number of deep (>10000 ft) light oil reservoirs in the Maracaibo Lake Basin with similar reservoir characteristics, currently under water injection at an advanced stage of depletion. In Venezuelan western reservoirs there are over 1.1 MMMSTB of oil currently in place in reservoirs with similar conditions. The selection of the VLE area as an Integrated Field Laboratory (IFL) [3] was based on screening criteria for WAG flooding, obtained from successful and unsuccessful worldwide projects [2], analytical simulation, experimental and numerical simulation studies, as well as availability of water and gas facilities. In this paper is described the first immiscible WAG injection pilot at VLE-305 in Maracaibo Lake focused on the monitoring process achieved with chemical tracers and productions curves. A better design, models and operational description of WAG process can be found in previous paper [4].

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe La Salina Field in the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina FIL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium gravity crude oil (25 °API) from LL-03/Phase III Miocene reservoir at 915 m (3,000 feet). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, spontaneous emulsification, interfacial tension between crude oil and ASP solution, chemical retention in the porous media, and physical simulation using reservoir core samples. The laboratory design involved twenty-three commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000 fold were observed for a variety of ASP solutions. Type IIand Type III spontaneous emulsification, both considered optimum, were observed. Linear coreflood results indicate that high molecular weight (partially hydrolyzed polyacrylamide) polymers can be injected into La Salina sand at about 800 mg/L. Radial sandpack corefloods produced an average oil recovery of 46% OOIP with water injection. Injection of 30% pore volume of ASP solution followed by 30% pore volume of polymer drive solution produced an average additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task since this will be the first offshore application of the ASP technology in the world. Preparation and transport of a phase stable ASP solution, through the injection lines and into the reservoir, that has the designed chemical concentrations and physical characteristics are crucial for a successful project. The initial decision for the plant design was to use an existing platform instead of a barge for construction of facilities. As a result, critical parameters such as: treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered.

Epidemics are considered paradigmatic states of emergency and humanitarian scenarios. Thus, humanitarian conceptualizations are negotiable through the very practices appearing in this type of emergency. This paper aims to investigate this process in relation to the 2014 Ebola outbreak, an event that is considered a global threat and an intolerable humanitarian situation. We analyze how the definition of what can be understood (or not) as humanity was constructed through visual representations produced by social media. We will also discuss how the definition of humanity was negotiated through dimensions such as the spectrum of visibility, the distribution of agencies, the affections intended to provoke, and the imaginaries defined. This paper is based on an empirical semiotic analysis of hundreds of images from the 2014 Ebola epidemic and 15 focus groups and individual interviews, performed over a span of one year, discussing images from social media.