SPE Latin America and Caribbean Petroleum Engineering Conference

A system of well monitoring in real time was developed, that is cost-effective and reliable. It allows the the obtained the real time data gattering.

Among the advantages of this system is the low price and effectiveness; as it uses low cost electronic components and an inexpensive communication network. The main electronic components used, are the Arduino controller and the wireless information transmitter using the free bandwidth in the world: 2.4GHz, which allows programming a more effective communication network (ZigBee Network); the power supply is based on photovoltaic cells (5V). The ZigBee Network Technology achieved its goal of keeping all interconnected points. The limited range of the transmitters (1500m) was overcome by the use of interconnected network points, which can build a grid to cover the entire field. The tested prototype was composite of four points in a transmition station – simulating a control room

The system is based on good quality and low cost equipment, that aims to reduce the production deferment and artificial lift equipment failures; by the implementation of a system that generates alerts according to the monitored parameters.

The in-line scavenging of hydrogen sulfide is the preferred method for minimizing the corrosion and operational risks in oil production (Rajagopal et al. 2009). On the other hand, it is known that Nanoparticles by their small size and high dispersion increase the probability of collision between molecules and minimize the diffusion problems. Additionally, oxides of iron, manganese, zinc, magnesium and copper are considered suitable sorbents for gas desulfurization at temperatures in excess of 300°C (Husein et al. 2010). The experiments were designed to apply nanoparticles for the streams treatment during enhanced heavy oil recovery (steam injection). Sorption of the H₂S present in oil phases finds application for mitigating H₂S forming during this process. In this study, our heavy crude oil whose viscosity is 10500 mPa.s, was obtained from a reservoir block of the Faja Petrolífera del Orinoco Hugo Chávez (FPOHC, Venezuela), with temperature about 80°C, and when the steam is injected temperature reach up to 260°C. Three types of nanoparticles were used to treat the heavy crude oil (H₂S scavengers and reduce viscosity). The organic matrix was high vacuum gas oil (HVGO) which serves as the carrier of dispersed particles, to reduce both H₂S production and viscosity, and the nanoparticles, based on transition metals that serve as H₂S scavengers centers are, respectively, FexOy, CuxOy and NixOy. In these experiments, before reaction, the sand and the gaseous products were separated to remove any catalytic effect from the minerals and H₂S present. Experiments were carried out in an autoclave reactor simulating steam injection condition (~600 psi and ~260°C). Appropriate quantities of heavy crude oil and water, and 500 ppm of dispersed nanoparticles were placed in the reactor; methane was used as reservoir gas. Results indicate the reduction of H₂S production from 1500 ppm in the experiment without nanoparticles up to 100 ppm, 250 ppm and traces to FexOy, Ni_xO_y and Cu_xO_y, respectively. Also, reductions of viscosity were obtained for all tests, from 15 to 26%.

Here we report the key success factors of the first polymer pilot at YPF in the south of Argentina and the consensus shifting strategy for polymer expansion in the current oil price context.

We calculated water flow velocities in the reservoir using three multiscale history matched simulation models. We found that more than 80% of water velocities across the complete field are below1ft/day [normally assumed reservoir water velocity for calculating the resistance factor in laboratory experiments].We increased polymer concentration in 10 to 30% to ensure good mobility ratio in the high permeability streaks possibly located in the channel bars. This is very important because low end point water permeability (<0.09) could explain the success of water flooding in friable formation with viscous oil. This challenges the common assumption of poor performance because adverse mobility ration (> > 10). High permeability streaks (above 10 Darcy) are not characterised because they are often lost during coring or they are not suitable for coreflooding experiments. Instead, stochastic history matching supports the idea of greater water end point permeability (>0.2) in the high perm streaks. Then, the target resistance factor for polymer could be underestimated (underestimation of polymer concentration) and polymer injection might not perform as expected. Simulation-based analysis of flows in the pilot zone strongly suggests that one of the key success factors was pattern confinement. The pilot configuration is five-spot with 4 injectors, 1 confined producer and 9 offsets producer wells. After injecting 0.15 pore volumes of 2500/3000ppm polymer we recovered more than 11% ooip incremental oil above waterflooding from the central pattern and more than 6% of the ooip from offset producers in contacted zone. The water cut reduced from 90% to 45% in the confined producer and from 87% to 67% in the offset producers. Water cut reduction and therefore the oil response is greater than best pilots in the literature. This can be explained because of the cross flow between fluvial layers in the inter-well region. Our simulations indicated that there was no out-flow of the central pattern. The very good performance in terms of low utility factor obtained so far (2.9 kg per incremental barrel of oil above water flooding) supports the hypothesis of the good confinement. The accurate simulation model allowed us to conceptualise a pattern rolling strategy for the polymer expansion that makes this technology economic for this low oil price context.

During produced water reinjection into an oilfield, the formation near the wellbore is progressively damaged due to total suspended solids (TSS) and oil particles in the injected water (OIW). This typically increases the bottom-hole injection pressure over time. Furthermore, if the water is injected in the oil zone, the initial bottom-hole injection pressure may already be high from the start due to water mobility constraint and oil viscosity. This study aims to model the generation of hydraulic fractures induced under different conditions, their geometrical characteristics and corresponding development over time. Such information is key to reservoir simulation for the secondary oil recovery and to reservoir integrity assessment.

Four disciplines are integrated into the proposed workflow: reservoir flow simulation, formation damage modeling, reservoir geomechanics, and the simulation of hydraulic fracturing. First, a sector model around an injector well is extracted from the full-field reservoir simulation of the case-study reservoir. In the reservoir flow simulation, a formation damage model is implemented, calibrated from injection rate, bottom-hole pressure, TSS and OIW actual data. At specified time steps, the flow simulator passes pore pressure profiles of the sector model to the geomechanical simulator, which computes the corresponding changes in stress and deformation.

The updated in-situ stress field, in combination with the petrophysical model applied for the flow simulation, is provided to the hydraulic fracturing simulator, which tests for the development of the hydraulic fracture and computes its geometry. The resulting hydraulic fracture is mapped back into the reservoir flow model to account for the local increase of permeability of the cells hosting the fracture. The workflow then enters into a loop starting again with the flow simulation, and the further development of the fracture under changing conditions is tested and modeled.

The proposed workflow was successfully applied to an injection well in an offshore field. Four scenarios considered different initial formation saturation, injected fluid viscosity and the conversion of a producing well into an injector. Multiple fractures with different characteristics, fully contained inside the reservoir, were predicted for each scenario and gave insights into the hydraulic fracture development during produced water reinjection.

The proposed method and workflow have the potential to significantly improve the reservoir simulation of the water injection process for secondary recovery or pressure maintenance by providing insights into how induced fracture geometries will influence the injection pressure and reservoir sweep efficiency. It also may provide valuable information to assess the integrity of reservoir cap rock during produced water reinjection.

There is a well-known theoretical chart that shows how compression, scales, liquid loading, corrosion, etc. appear as a gas field decreases production due to reservoir depletion. The approach of this paper is ambitious and will demonstrate and exemplify how these problems appeared in our gas field, and share the techniques, methods, and procedures we went through to satisfactorily handle them.

This paper shows the development of a gas field placed in the Golfo San Jorge Basin (Argentina) including the different life stages of the field (High/Medium/Low Pressure) with the related problems in Facilities, Flow Assurance, and Liquid Loading, and finalizes with an introduction to the future problems we are expecting.

Throughout the paper, we will show the changes we went through, lessons learned, and conclusions related to the following topics:

+ Facilities → Slugging in flowlines/changes in suction pressure/new facilities

Not many papers cover in such an integral way the development of a conventional gas field with a large exploitation history as this work does, where the field dates from the 2000s.

This paper sets a reference and fills a gap in terms of an overall look at all problems together, and integrates the theory from the literature, information from field experiences, best practices, and the application of new technologies/methodologies. Challenges for future exploitation are presented as well. Reading this paper will help in understanding the complexity that those people involved in the management of a gas field will face as their reservoirs deplete and the production of the wells goes down.

In this study, the historical production of VacaMuertais evaluated aiming to capture the complexities of this formation in terms of fluids production and recovery performance. This paper integrates the Neuquén province production analysis with the objective to understand the oil and gas historical production behavior in a development area of roughly 12,000 sq mi (31,000 km²).A comprehensive evaluation using public data was conducted to present the contribution and the impact of VacaMuerta oil and gas production on the region and the country.

The VacaMuerta formation represents the most-challenging source of new oil and gas in Argentina, with a huge potential considering the size of the development area in any block across the basin, the reservoir gross thickness and the resulting fluids in place, and the way forward to be achieved regarding the balance between well cost reduction and productivity improvement. There have been important drilling and development efforts in the last 4 years in which both vertical and horizontal wellbore configurations have been implementedand tested over the longterm. However, there are still uncertain factors under evaluation to assess the VacaMuerta formation performance, which achieved 29 million barrels and 124Bcf in December 2016, with 674 oil and gas producer wells.

The workflow focuses on the analysis of historical production for both vertical and horizontal wells, average rates and cumulative production of initial 6 and 12 months, water cut and gas-oil ratio (GOR), decline analysis and vintage performance, with the addition of heterogeneity index plots. Production history statistics and probabilistic analysis were incorporated in the study to summarize and present the evaluation results. Important aspects related to well decline behavior and estimated recovery for the initial years were also analyzed.

In this paper, we present the main findings and results of a complete production analysis of VacaMuerta formation after more than 10 years of production. This paper provides an overview of the historical production performance and the key elements for production forecasting. The integration of this production information with geology, reservoir characterization, well design, and completion and operation strategies provides an essential reference to improve the understanding of the production potential and the visualization and ranking of any well, field, or area in the Neuquén basin.

More than 96% of Saskatchewan proven initial oil-in-place is contained in reservoirs that bear thickness less than 10m. This limits the application of thermal enhanced oil recovery methods as heat preservation turns to be burdensome. On the other hand, solvent injection has proved reasonable recovery performance on heavy oil production. In this regard, cyclic solvent injection (CSI) has engaged petroleum industry's interest to be a viable technique for heavy and extra heavy oil recovery.

In this study, diluted Saskatchewan oil samples with viscosities of 1850, 6430, and 22000 mPa.s at T = 20 °C are tested. Two sand pack models with permeability of 6-10 D and porosity of 27-32% are subjected to series of pure and mixed solvents such as CO₂, CH₄-CO₂, and C₃H₈-CO₂ cyclic injections at various pressures and mixture compositions. First, oil sample with the viscosity of 1850 mPa.s is tested and optimum solvent pressure and concentration of aforementioned solvents are determined. Thereafter, sets of CSI experiments are performed (under optimum solvent pressure and concentration) using extra heavy oil samples with viscosities of 6430, and 22000, mPa.s to find how CSI performance is affected by the heavy oil viscosity.

Results show that higher operating pressure yields more oil recovery factor for cyclic CO₂ injection tests as ultimate oil recovery factor increases from 35.6% at 1.72MPa to 57.35% at 4.82MPa. In addition, higher concentration of propane results in more cumulative oil production, while in the case of methane, the recovery factor reduces with increased methane concentration in the CO₂ stream. The highest recovery factor of 73.8 % is obtained by injecting mixture of 50% propane and 50% CO₂ at 1.72MPa on the oil sample having viscosity of 1850 mPa.s. The results of cyclic tests on the extra heavy oil with viscosity of 6430 mPa.s are in line with those obtained from tests conducted on the first heavy oil sample; however, the recovery factors are lower by almost 20% since the solvent solubility is noticeably lower in extra heavy oil samples. Interestingly, no oil production is observed after conducting the first cycle injection of 50% C₃H₈ - 50% CO₂ on extra heavy oil with viscosity of 22000 mPa.s.

The objective of this paper is to estimate the long-term energy mix – i.e. the combination of resources including solids, liquids and gases that will satisfy energy demand to the year 2040 – with a Global Energy Market model (GEM). The GEM provides a close match of the historical energy mix dating back to the year 1850 and is then used to make forecasts for the future. Originally developed in 2007, the GEM was used to project the energy mix to the year 2030. In the present paper, the validity of the original projection is tested against the most recently available data.

The GEM estimates the fractional contribution of different primary energy sources to the global market. In total, there are six parameters that allow the GEM equation to give the best possible match of the historical energy mix. Using the estimated parameter values, the model can then be extended into the future, providing a reference case and alternative scenarios of the energy mix based on evolving unconventional, conventional and renewable resource quantities, costs, technologies, economic growth, population and policies.

The original GEM findings from 2007 forecasted a "2030 1/3 forecast", indicating that solids, liquids and gases would each occupy a third of the energy market in the year 2030. After further disaggregating the categories, it was found that liquids, mostly, oil would experience a declining market share by 2030 while natural gas would see a rapid rise. The share solids, mostly coal, was relatively flat by that time. Our new results show continued penetration of natural gas in the energy mix – a result consistent with efforts to reduce carbon emissions.

Our proposed paper is novel in that it uses the most recent statistics of the last 10 years on consumption of different energy sources to verify the accuracy of the original GEM projections carried out in 2007. Once the results are proven reasonable, new scenarios are developed with an extended time horizon to the year 2040.

Liquid loading is a significant issue within gas and gas condensate wells, resulting in production decline and rate instability. The Southern Gas Field serves as a case study, to investigate a field experiencing liquid loadup. The field is located in the Southern North Sea, and is being produced via natural depletion with no pressure support from the surrounding aquifer. In Yr. 9 production well A ceased to flow as a result of liquid build up, and by Yr. 11 well B also showed signs of liquid loading. The load fluid consisted of liquid condensate, and this was confirmed by wireline investigations. A decision was made by the operator to deploy two 2 3/8" velocity strings, in an attempt to extend the field lifespan, by restarting well A and returning rate stability to well B. Velocity strings are a relatively low cost deliquification method, that aim to increase the gas flow rate above the critical flow rate, enabling the well to continuously unload liquids. The design of velocity strings is crucial, as if too small a tubing is used, the velocity string can act as a choke, suffocating the well. The velocity string run in well B proved a success, however the workover in well A failed to restart the well. Batch foamer treatments were later tried in well A but proved ineffective. The effectiveness of foam to deliquifying gas wells, depends upon the composition of the load liquid, as both water and liquid hydrocarbons react differently to surfactants. Typically liquid hydrocarbons such as condensate do not foam well, and must be agitated to maintain foaming.

This study aimed to make use of Petroleum Experts Integrated Production Modelling (IPM) software to model the effect of the velocity string deployment, with regards to returning rate stability. Prosper models were created and Systems Analysis was performed and confirmed that 2 3/8" velocity strings will lift both well A and well B out of the Turner region. Prosper was also use to model the effect of using foam as an artificial lift method, with the results identifying that the water gas ratio (WGR) of the field is too low for effective deliquification using foams. A GAP model was also created for the Southern Gas Field to determine the incremental reserve gains to be had by deploying velocity strings. The simulations identified that well workovers can provide an additional 4.99 Bscf to the recoverable reserves.

Throughout a waterflood project, injector wells can experience scale build up mostly related to formation-water incompatibilities; as a consequence, injectivity index (II) decreases and vertical conformance can suffer leading to poor sweep efficiency. Stimulation treatments are required to reestablish well injectivity; usually Hydrochloric acid and Regular Mud Acid are used in sandstone reservoirs. Such treatments involve a number of difficulties such as handling highly corrosive fluids, risk of clay instability, secondary reactions and time-consuming flowback of spent treatment in low pressure reservoirs.

Recently, a novel chemical was identified to effectively dissolve scale obstructions in injector wells while avoiding the operational constrains found in traditional acidizing jobs, including the need of flowback. Fluids containing the environmentally friendly chelating agent Glutamic acid N, N diacetic acid (GLDA), were tested in the laboratory under downhole conditions to evaluate the dissolution of a scale sample from the field composed by Fe₂O₃ and CaSO₄. Additionally, core-flood, compatibility and corrosion tests were carried out to evaluate the interaction with clays, formation and well's metallurgy. Results showed effective dissolution of the scale sample, while being fully compatible with formation clays and fluids which indicated that the treatment could be left downhole and pushed into the formation without causing further formation damage. Furthermore, corrosion tests showed no need of corrosion inhibitor for a low carbon tubular under tested conditions.

Field implementation took place in an on-shore injector well completed selectively with injection valves between packers. A two stage treatment was designed; the target of the first phase was cleaning out the injection valve itself and the tubing-casing annular space of this interval, and the second stage aimed the dissolution of scale located in the perforations and deeper into the formation. Step rate tests were performed before and after the treatment to evaluate well injectivity. Low injection treatment rates and soaking allowed enough time for the GLDA to effectively dissolve the scale obstruction along the treated interval; spent treatment was pushed further into formation once regular water injection was reestablished with a 51% increase in its injectivity index. The use of GLDA in the field was considered cost-effective due to the lack of additives, no need for of N₂ to kick-off flow-back, nor flow-back fluids neutralization and disposal.