The present work aims to expose the study and development of a potentially disruptive change of focus in the mechanical sucker rod artificial lift system. This is a new solution based on the installation of a linear speed reducer located at the bottom of the well between the pump and the rods. This new configuration pursues the goal of dramatically reducing loads on the rod string, surface equipment and power motor, thus allowing to expand, in efficiency and field of application, the limits of the sucker rod pumping, and in some cases of the artificial lift systems as a whole.

Many fields in Argentina have multilayer reservoirs that require various stimulation techniques, primarily hydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields) and unconventional (tight gas and shale), are the main focus in the Golfo San Jorge and Neuquén basin. The hydraulic fractures created in these basins present a variety of conditions and challenges related to depth, well architecture design, bottomhole temperature (BHT), reservoir pressure, and formation permeability.

In 2006, a pinpoint completion technique was introduced to help achieve greater efficiency and reduce time and costs associated with completions. This paper presents experiences gained using this technology and proving such versatility in different types of reservoirs.

The pinpoint technique, called hydrajet perforating annular-path treatment placement and proppant plugs for diversion (HPAP-PPD), was applied in new wells at different reservoir conditions. The history and evolution of this technique in Argentina was initiated in conventional oil reservoirs (mature fields in Golfo San Jorge) and then was introduced in the Neuquén basin in gas well completions. Throughout the last seven years, this technique has been tested and implemented in tight gas wells. More recently, it was used to improve a completion technique in a shale oil well.

This completion method allowed operators to focus treatments in desired zones using specific treatment designs based on reservoir characteristics. Several case histories are presented for different basins, formations, and reservoirs types, highlighting lessons learned and reduced completion time.

Given the impact of CO₂ emissions on the environment and the direct correlation to the petroleum industry, it has become evident that our industry must minimize the carbon footprint associated with hydrocarbon production and consumption. One of the obvious choices for utilizing CO₂ in the industry is associated with enhanced oil recovery (EOR). The injection of miscible/immiscible CO₂ EOR is one of the most attractive techniques in these days for oil industry. As part of this investigation, it is important to assess the source/storage of CO₂ to ensure reliability and continuous supply. In addition, it is critical to appropriately design the injection rate of CO₂, distribution facilities, and the instrumentation for safe operation.

In this paper, a case study is completed and facilities design are shown as potential sources of CO₂ gas handling process. It is also discussed the potential challenges associated with bulk CO₂ storage, compression, transportation and injection. Moreover, an evaluation of existing technologies for CO₂ handling facilities is conducted to ensure the desired injection fluid specification.

A complete CO₂ pipeline network system is developed to determine optimum discharge pressure and design of pipelines specifications is also outlined. The results show that the pump discharge pressure at NGL - CO₂ source must be 3,420 psia to meet the 2,850 psia injection wellhead pressure. Also, the ANSI-2500 piping class meets the high injection pressure requirement. In addition, the pipeline network simulation model shows that the optimum pipeline size should be 8 in.

The developed design of Case study CO₂ injection facilities is the first CO₂ injection project in the company's history. This case study along with its finding will greatly help in controlling the CO₂ emission in the environment.

Water is the most commonly used injection fluid for flooding/energizing oil reservoirs. Despite oil price fluctuations, water use has continued because of its wide availability, relatively low cost, and ease of handling. Decades of research and field application experiences have yielded a sound theoretical approach and practical knowledge of the subject. Nevertheless, water injection deployment and operations can still benefit from optimization. This paper discusses the state-of-the-art use of numerical optimizers based on smart algorithms and stochastic machines that couple subsurface, surface, and economic models.

During planning and operations of waterflooding projects, many decisions are made, such as the number, location, and drilling sequence of new injector and producer wells, total and per well injection rates, well conversion, and fluid withdrawal rates. In addition, each decision variable has multiple options, which combined can generate hundreds or thousands of scenarios, raising the key question of how the optimum scenario can be determined in a timely manner. Furthermore, the optimum scenario selection process should consider uncertainty (e.g., reservoir properties and oil prices) as well as operational constrains.

Based on previous experience, a general workflow was developed and fine-tuned to help identify optimum scenarios. The workflow begins by defining the scenario matrix using available validated history-match models. Models are coupled with an automatic optimizer/stochastic machine. The study cases considered reservoirs with heavy-to-medium oil, injection by pattern and flank, large variations in original oil in place (OOIP), and number of wells for waterflooding implementation and reactivation planning.

Optimization runs typically require hundreds of iterations to approach the maximum or minimum objective business function. Each iteration corresponds to a scenario. To identify the optimal scenario quickly, various strategies were tested: parallel computing and new methodologies of sequential optimization with reduced number of decision variables, initial exploratory runs with a shortened economic horizon time, and stochastic analysis of selected scenarios of the optimization run. All of these strategies proved successful, depending on the specific situation.

The workflow application in three case studies yielded approximately 30% cumulative production and net present value (NPV) increments, with less economic risk than the traditional deterministic simulation approach and reduced water cut up to 40%; compared to base scenarios, Np and NPV increases higher than 200% were obtained. Furthermore, the workflow application generated a large number of scenarios that provided flexibility to modify operations during unexpected events.

Optimizers/stochastic machines were determined to be a valid means to quantitatively estimate the economy and risks and are a fundamental tool for managing waterflooding projects, resulting in better scenarios than the traditional deterministic approach. The approach is also applicable to all types of enhanced oil recovery (EOR) projects.

The objective of this paper is to introduce the Uruguayan Petroleum Fiscal Regime and to compare it against worldwide standards, with regards to the most commonly used statistic: Government Take, but also using other important statistics like Effective Royalty Rate, Savings Index, Lifting Entitlement and Progressivity. The ultimate goal is to measure the attractiveness of the Uruguayan oil and gas fiscal regime.

Based on the probabilistic model of a hypothetical oil and gas field development offshore, and Production Sharing Contracts cash flow diagrams, the Government Take, Effective Royalty Rate, Savings Index and Lifting Entitlement were calculated and averaged for all the Production Sharing Contracts in force in Uruguay. In addition, the Progressivity of the Uruguayan fiscal regime for oil and gas was tested, a crucial feature of the fiscal regime design considering the fluctuations in crude oil prices. The calculated mean values were compared with international petroleum contract averages obtained from literature.

Regardless of the fact that third party assessments attribute important volumes of hydrocarbon prospective resources to Uruguayan frontier basins (USGS 2011, 2012), there has never been a discovery in them yet and the geological risk is still significant. The main results of this work are that the terms of the contracts in force result in an average Government Take of approximately 70%, comparable with the Government Take of several hydrocarbons producing countries. Additionally, the calculated average Effective Royalty Rate was 9%, the Entitlement for the IOC averaged 52%, and the Savings Index resulted in 48%, all of them among worldwide standards. The Uruguayan fiscal system proved to be progressive, revealing state-of-the-art fiscal design. The overall conclusion is that the Uruguayan fiscal regime is fair (or could even be regarded as too harsh) considering the geological risk of the country's basins.

This work is useful for petroleum companies interested in assessing the hydrocarbon exploration and production potential of Uruguay, to easily compare the contract economy and its fiscal regime with other destinations. Furthermore, it might provide good insight to authorities to understand the attractiveness of the Uruguayan petroleum fiscal regime for design improvements.

Located in eastern Venezuela, the Furrial field is composed of three main reservoirs. Reservoir characteristics include 8,300 million barrels of original oil in place and a hydrocarbon column consisting of crude with asphaltenes that vary from 10 to 30° API. The field has 147 active wells, of which 45 are water-injector wells and seven are gas-injector wells. Wells drilled in the area range from approximately 12,000 to 17,000 ft. Crude oil with asphaltenic tar mats (because of its chemical features) was identified in the field, which establishes a vertical structural seal bordering traditional reservoirs. Major problems in the reservoirs include emulsions, paraffin and asphaltene plugging, water cuts, and water channeling. For several years, the operator has been developing a program to convert wells that cannot be produced naturally to gas-lift wells (conventional, tubing punch, and coiled lift) to increase recovery potential. Although the system is a single, economic, and fast-lifting system, it requires a continuous flow of high-pressure gas.

The productivity workflow presented in this paper required a multidisciplinary team to analyze, select, and rank recommended well candidates for intervention and production optimization, evaluating all aspects pertaining to well productivity and reserves to objectively identify possible alternatives for increasing production. The process produced a list of wells ranked by their potential to increase production. The intervention plan for the wells were then defined and ranked based on technical and economic criteria.

This paper presents the successful application of this methodology in a mature field in the Venezuelan Oriente Basin and demonstrates how the method impacted and improved well productivity in this field by over 27 times more than the base case.

As a kind of water saving and green fracturing methodology, the innovative LPG fracturing fluid system that is developed by Gasfrac is known for its low density, viscosity and surface tension, making satisfying achievements in McCully Gasfield in Canada. However, it has not been applied by scale in China and requires further analysis.

The LPG fracturing technology was analyzed technically and its physical properties were studied, including viscosities and surface tensions of water, butane and propane within various temperature ranges. A LPG fracturing phase control diagram and a fluid capillary pressure diagram were drafted. Production data of many shale gas wells in McCully block were analyzed to accomplish the fracturing flowback formula. The economical analysis of the LPG fracturing technology was completed, including the overall cost of slickwater fracturing fluid and water treatment, as well as the overall cost of LPG fracturing fluid and its integrated devices.

The slickwater fracturing fluid has been widely used in China to exploit shale gas, which wastes a lot of water and does harm to environment. The LPG fracturing technology utilizes liquefied petroleum gas as the fracturing fluid that mainly consists of propane with ethane, butane, propylene and some additives, so it is harmless to formation. Compared with conventional hydraulic fracturing, the LPG fracturing fluid is mixed with chemical additives when being pumped and it becomes a kind of viscous fluid like gel, so that proppant particles may be evenly distributed in it and they don't deposit along fractures. Besides, fractures are higher and the production life of gas wells is improved. Propane mixes with natural gas completely and it may reduce the oil's viscosity after contacting it. Therefore, there is no need of flowback and water treatment procedure. Injected in a closed loop, the LPG fracturing fluid is operated via a remote computer and monitored by sensors distributed in the operation area, so that LPG leakage risk is reduced and the fracturing operation may be carried out safely.

Shale gas is being widely exploited in Sichuan Province, which is located at the source of Yangtze River. In Ordos Basin limited water sources make it very costly to prepare conventional fracturing fluids. The slickwater fracturing fluid is cheaper than the LPG fracturing fluid, while water treatment costs more. All in all, LPG fracturing technology shall be recommended in China that suffers from severe environmental risks and water scarcity.

This paper presents an extension of the RMFinder technique, previously proposed to identify representative models (RMs) within the decision-making process in oil fields. As there are several uncertainties associated with this decision-making process, a large number of scenarios are supposed to be analyzed, so that high-quality production strategies can be defined. Such broad analysis is often unfeasible, so techniques to automatically identify RMs are particularly relevant. The original RMFinder does not consider the individual probability of each RM, which may not be accurate when the risk curves of the problem are estimated. Therefore, a mechanism to calculate the individual probability of each RM was developed here, together with a graphical way to visualize different proposals of RMs. To automatically identify the optimal probability of each RM, this new version of RMFinder minimizes the deviation between the risk curves generated with the selected RMs and the original risk curves of the problem. The graphical approach automatically exhibits, in a single page per solution, the RM dispersion in the scatter plots, the resulting risk curves and the differences between attribute-level distributions. This helps the decision makers to visualize and compare different sets of RMs. The proposed methodology was applied to a small synthetic problem and to three reservoir models based on real-world Brazilian fields: (i) UNISIM-I-D, a benchmark case based on the Namorado field; (ii) UNISIM-II-D^β, a benchmark case based on a highly fractured pre-salt carbonate reservoir; and (iii) ST001a, a highly heterogeneous heavy oil offshore field. The obtained sets of RMs were evaluated by experts and considered appropriate to the studied problems, being adopted as the standard models in the following steps of the decision-making process to define the production strategies under uncertainties.

Exploration and production of heavy and extra heavy oil have always presented challenges that gradually have been overcome by reservoir engineers through the application of new technologies like downhole heating and diluent injection. However, it is recommended to conduct pre-assessment studies of these technologies in order to optimize resources associated with the implementation phase and subsequently with a large scale implementation of these technologies in the field. One successful example where this pre-assessment study was applied, is the one performed in the Huyapari field located at the Orinoco Oil Belt, currently with more than 600 active horizontal wells where the productivity of the wells could be affected by the frictional pressure losses in the horizontal section. This is the reason why the main objective of this paper is to develop a reliable methodology to conduct a pre assessment study of the downhole heating cable technology by the integration of different methodologies such as analytical and deterministic analysis, operational evaluation, and numerical simulation. Based on the results of the implementation of a downhole heating cable in the A-P10 well (producing with downhole heating cable since 2005) and the representation of these results by numerical simulation, it was established a procedure that takes into account the characteristics of the reservoir and some operational variables.

The boom of organic shale plays has revealed the critical need to correctly size hydraulic facture treatments to achieve commercial success in those reservoirs. The right balance must be found between the cost of fracturing and the additional production achieved by increasing the formation-to-wellbore contact area. Such a balance is formation specific and depends on the reservoir properties and local well completion costs. This paper examines a wide range of completion scenarios to evaluate the relationship between hydraulic fracture design, production, and well profitability using numerical simulations to guide completion of horizontal wells in the Vaca Muerta shale.

Evaluation of the interaction between completion and production requires an integrated approach including both static (petrophysics, geomechanics, and the characteristics of natural fractures) and dynamic (reservoir fluid, conductivity degradation, and reservoir pressure) properties. The hydraulic fracture geometry is determined using a state of the art simulator that models the physical mechanisms of elastic deformation, leakoff, proppant transport, and the interaction between hydraulic and natural fractures. The explicit description of the hydraulic fracture geometry ensures that any variation in the completion design is consistently taken into account. Hydraulic fracture geometry is then directly fed into a reservoir simulator to evaluate the anticipated production. The resulting production profile is then input to an economic model to assess the profitability of the proposed scenario. The model is based on the latest understanding of the Vaca Muerta shale and is calibrated by reproducing the average historical production of the play.

A sensitivity study is performed to investigate the impact of each completion parameter. Proposed sensitivities consider a large range of completion design parameters for a horizontal well, such as the type and volume of fracturing fluid and proppant, number and spacing of perforation clusters, and staging strategies. The sensitivity analysis covers more than 60 completion scenarios over 550 fracturing stages and 1,600 individual hydraulic fractures. All the simulation cases are combined in a database to quantitatively evaluate the impact of completion design over the hydraulic fracture dimensions and production, and highlight its main contributors. Total volume of proppant per well and perforation cluster spacing show a good correlation with production. This production increase can be linked with an increase of the propped surface highlighting the need for the right balance in between fracturing fluid viscosity to enhance transport and the proppant concentration to compensate for total treatment volume. The results of this study provide practical guidelines for optimizing completion of horizontal wells in the Vaca Muerta shale.