This technical work describes the path to implement full casing rotation during primary cementing jobs. Explain and share leading edge results from this innovative method, which has allowed performing highly difficult cement jobs with good quality results at the first attempt at country level. In our current challenging drilling environment, a competent annular zonal isolation is required for long-term integrity. The well known worldwide cement practices has been key to obtain good results, among them, casing rotation has been widely applied to liners but not so commonly to full casing strings until now; custom fit rotating cements heads were implemented to improve current cement results. The pathway followed to implement this technology considered different activities in a time lapse of three years; starting by evaluating the operator's needs, until achieve a full technology massification in place supported on required results. Rotating cement heads have been widely used in a variety of fields within Colombia. At Llanos basin, they have been used to improve bond results in front of very washed out sections near the casing shoe; at superior and mid valley basins, they have allowed obtaining good selectivity between productive zones in very long cement columns. In other areas, this technology has allowed to replace the well-known casing reciprocation practice granting safer practices. This technology has been appointed as the first option to obtain required isolation results for exploratory wells. Nowadays, jobs that in the past had little to no chance of success have been performed under total control with exceptional results avoiding extra remedial costs. In summary this technology has broadened the chance to improve results, allowing to perform a cementing operation under best in class HSE practices, granting the operator to obtain the required solution and providing the way to maximize the value added from mature fields. Use of casing rotating cementing heads is a new trend for the oil industry that allows the operator to obtain cement job results at the very first attempt, reducing costly remedial jobs and maximizing the cement bond to formation and casing, hence, improving the production results at a large scale and boosting wells integrity.

This paper summarizes the strategies implemented in a mature oil field in Ecuador to revive its production by improving energy efficiency, increasing fluid production and incorporating proved reserves. Results are shown in terms of the field energy efficiency index, energy consumption on ESPs, oil production, annual production decrease tendency and reserves incorporation. The Choke Model philosophy was implemented as a strategy for field development optimization. This methodology allowed the operator to identify that the main chokes were the production wells and the power. By using divergent and convergent thinking techniques focused on these chokes, four main strategies were selected: reduce the pipe diameter size of a fluid line, artificial lift system energy assessment, reactivate closed wells and recomplete others. Complete description of the methodology is provided in detail to permit readers to analyze this successful case. The reduction of pipe size diameter of a fluid line increased the mobility of the fluid from the well pads to the plant, eliminated the recirculation of water and thus increase the energy efficiency indicator of fluid handling from 9,770 to 10,190 BFPD/HP. The energy assessment of the artificial lift systems identified the inefficient wells that were scheduled for ESP redesign and technology upgrade with an energy improvement of 30%. All these energy efficiency improvements lead to rise fluid production. Based on the possibility to increase fluid production, wells reactivations, ESP upsizing’s and recompletions were planned. The team used a screening process to optimize candidates, gaining 2,010 BOPD, in average, over the baseline production profile since September 2017 to December 2018. The activities performed and well interventions diminished the annual oil production decline rate from 14% to 8%, allowed the operator to incorporate 4.8 MBBLS of proved reserves in 2018 and generate 7.6 MUSD of free cash flow in the same year. All the strategies were successfully achieved, and they accomplished the objectives of reviving a mature field, extending its life and generating value for the operator. None of the previous were possible without rethinking energy sustainability and reservoir management. The novelty of this work is the multidisciplinary approach and innovation methodology implemented to provide solutions to operational field chokes by identifying feasible projects in terms of technique, time and economics.

The main objective of this project is to develop a model that, based on the data of previously drilled wells, allows the user to evaluate the mud plan and identify the probability of a stuck pipe event occurrence. This is done, by using statistical predictive models, particularly in this case, neural network models. The proposed model takes the input data from the Volve’s dataset. The process starts with the pre-processing of more than 24.000 rows of data from the daily drilling operation reports of 30 wells. The pre-processing of the data consists of identifying the cases where the operation ran across a section successfully or when it resulted in a stuck pipe event. Depending on whether there is or not a stuck pipe event, each row will be classified indicating the chance that a stuck pipe event occurs based on the geological and the operational conditions. In order to ease the processing of the 24.000 rows, the project workflow implements a Natural Language Processing model, which, based on an initial dataset of 1.200 rows, reads the remaining 22.800 identifying whether the row content is relevant or not for stuck pipe identification. Once all the rows are processed, the rows which represent a stuck pipe event, and those who identify a clean operation run are selected and integrated into the final dataset. Once the data is processed, the resulting dataset consists of around 600 rows. After some data transformation, this dataset will be the input for the neural network model in the training and validation phases. Once the model is built, the model is tested with the validation dataset in order to evaluate its accuracy. The trained model shows high accuracy, higher than 84% on the test data. After the model is trained and validated, it’s implemented into a frontend which will serve as the front user interface where he can upload the mud plan parameters, and obtain a stuck pipe event chance evaluation. Having these results, the user can improve the mud plan in order to reduce the chance that an event of this type occurs. The main advantage of this methodology is that it allows to include historical data from the other drilled wells, this way, boosting the mud plan design with real data and reducing the chances that a stuck pipe event, that account for a high percentage of NPT’s during drilling operations occur. Also, by the use of these statistical models, applied to a specific field, it will allow to intrinsically take into account variables such as geomechanics properties in the model.

It is a common practice to evaluate an injection pilot before a field-level implementation of waterflooding, but this requires early investment in facilities and construction time. An alternative solution is proposed as a modification of the dump flooding concept: Produce water from a low-salinity aquifer and inject it into an oil reservoir within the same well, using a closed system. The modification of the conventional dump flooding design consists of adding surface monitoring and control capabilities, which for this mature field is a local regulatory requirement A comprehensive process for the completion design considered reservoir, well and operational conditions as both new and existing wells were considered as candidates for these completion systems. The design consists of a concentric completion with packers to isolate both the water aquifer and oil reservoir. Water is produced from a deeper low-salinity aquifer with excellent water quality through an Electric Submersible Pump (ESP) that also serves as an injection pump. At surface, the water rate is measured by a flowmeter and then injected into the same well through a concentric string to a shallower oil reservoir for secondary recovery. A simple closed-loop system at surface eliminates contact with oxygen, minimizing future corrosion problems. The high quality of the water (low salinity, without solids, O 2 , H 2 S or Fe) eliminated the need for water treatment. Four wells have been successfully completed using this design, currently injecting at the required rates without presenting any functionality problem. Additional three wells are in schedule to be completed in order to accelerate waterflooding implementation in areas either remote or environmentally sensitive with no nearby water source. In these areas, implementing a waterflooding conventional pattern that requires connecting water producers and injector wells would require lengthy permission processes for long high-pressure lines and additional time for the construction of those water transport pipelines. The completed modified dump flooding wells decreased the implementation time of the waterflooding pilot project from 2.5 years to 5 months. Additionally, the environmental footprint and facilities investment has been reduced by an estimated 90%. This is the estimated cost savings when comparing the investment in dump flooding well construction versus conversion of existing wells to water producers or injectors and the investment in facilities, including water treatment plants, to connect those wells. This paper presents the main design and operational considerations before execution, deployment challenges, and lessons learned and recommendations from the execution of the first campaign

A new Integrated Exploitation strategy to boost production and incorporate reserves at the Ecuadorian Bloque 61 was put on the table to radically change the production strategy from primary to secondary recovery in only two years timeframe. This was accomplished by drilling appraisal, development and infill wells in conjunction with peripherical and pattern waterflooding. The project departed from reservoir characterization and modeling to identify the potential targets for waterflooding. The identified opportunities were assessed and ranked. Consequently, several pilots were implemented as a proof of concept. Once the waterflooding pilots were in place, the complexity of the reservoir was evaluated. To account for the subsurface uncertainties, a probabilistic approach was followed to do the economical evaluation and risk management for the expansion. Novel facilities configuration, implementation of new completion design and production enhacement techniques, along with a robust surveillance plan played a key role for the rapid implementation of a new exploitation strategy. Positive reservoir pressure response and incremental production were observed within one to three months right after injection started in the pilots. This behavior was similar for the other fields where waterflooding was expanded. As such, new wells drilled and well reactivations in areas influenced by waterflooding has proven to have a threefold increase in expected initial productivity, therefore, the increase of reservoir pressure opened new development opportunities in Block 61 in former depleted reservoirs. The implementation of a new exploitation philosophy focused in secondary recovery, increased recovery factor in about 10%, the contribution from waterflooding is about 30% of the total oil production. Additionally, 50% of the volume to be developed, corresponds to activity to be completed in Waterflooding areas. This waterflooding strategy represents a shift in the exploitation paradigm in the Ecuadorian E&P industry, by going beyond the pilot execution through proper risk and uncertainty management as a path to full-field implementation. To fast-track this deployment of the water injection, a closed loop system was implemented between the water source and the injector to reduce facilities costs up to 80% as no treatment is required for the injected water.

The current demand for fossil fuels will promote the search for techniques to increase hydrocarbon production, so methods are needed to accelerate the development of this resource. The use of computer tools in the oil industry is indispensable today; we use increasingly powerful algorithms that perform extremely complex analyzes, which enable us to obtain solutions to previously affected problems pending in the industry. Most of the time the lack of parameters forces engineers to limit the study of a well, making restrictions and predictions not so accurate, especially regarding production; Based on this, the main objective is the development of a computational tool that allows to calculate the production potential of the wells drilled in the Huyapari field, which will use the python programming language, encoded from such a way to perform the calculations under the statistical methods of the analogous wells, the Joshi equation and nodal analysis. This tool is divided into two phases: the first is the calculation of the potential for pre-drilling and post-drilling of wells; the second phase is the adjustment of the potential that is carried out by means of the individual nodal analysis of each well taking into account the current reservoir pressure and the immersion limit of the pump.

The objective of this paper is to present a timeline of the different well designs used in Llanos 34 Block that led to obtain the slimmest well design possible, indicate the challenges experienced with every well design, and the casing design recommendations and developments to mitigate these challenges. Within this paper, we present the challenges that led to a new well architecture and the results in the field. The paper includes the detailed engineering analysis for the new architecture, including casing design, and torque and drag analyses. Additionally the paper compares the results in the field with the engineering analysis to validate the inputs and models. Finally, the paper includes a summary of the cost reductions of the new architecture and the lessons learned related to the models, operations and casing connection technology. Different alternatives of well design were analyzed for the wells to be drilled in Llanos 34 Block, depending on the horizontal displacement required. Initially, a three section well was design with horizontal displacement of 4,000 ft or higher, considering a 9 5/8" production casing with a high collapse grade; and another option with a two sections well design when the vertical section was below 4,000 ft, with a 7" production casing. This alternative presented the opportunity to optimize costs and drilling time. The engineering analysis for the new architecture presented a challenge for running 7" casing in a longer open hole section; with very high values of torque expected. The casing connection manufacturer worked to improve the design of the connection to reach the required torque. In June 2016, the operator drilled the first well with the new architecture obtaining very good results, reducing cost and improving service performance. As a result, the new architecture became the standard with 46 drilled wells from June 2016 to June 2019. This paper includes the engineering analysis of new highly deviated wells and the casing connection technology developed for these new requirements. The experience obtained by the optimization of the well design in Llanos 34 Block and the technical challenges faced by the production casing, can provide to different operators ways to optimize their well designs.

As part of an exploration campaign in the Sub Andean region in Bolivia, Repsol faced a unique challenge to reduce well construction costs while drilling through harsh and abrasive Caipipendi Block formations. The Caipipendi Block poses several drilling challenges that often lead to premature bit and underreamer cutting structure damage. Two main points were targeted as fundamental to accomplish this objective: reduce the number of runs to drill the Carboniferous section and improve borehole enlargement efficiency. A multidisciplinary group comprising a service company and Repsol team members conducted a detailed and thorough investigation of previous failure modes to identify an integrated approach to improve the performance. Along with offset history, the team was able to identify lithology characteristics to accurately diagnose the underlying root causes. To tackle the hard and abrasive Upper Carboniferous section, a customized polycrystalline diamond compact (PDC) drill bit was equipped with 3-D cutter (3DC) technology and powered by a combination of an enhanced power section and a robust rotary steerable system (RSS) tool with a new specific steering pad feature. A new reamer concept was also applied in this well to mitigate the anticipated drilling shock and vibration associated with underreaming through the challenging strata—without compromising drilling efficiency. To achieve the desired performance goals, 3DC elements were applied to the drill bit, along with a robust RSS designed with a pioneering steering pad developed to sustain performance in high levels of formation abrasiveness. To increase borehole enlargement efficiency in the Devonian section, a new cutter block was designed. An advanced 4D transient drillstring dynamics modeling package was used to analyze failure modes, design the reamer and drill bit cutting structures, predict the drilling dynamics of drill bit and reamer, and recommend drilling parameters for the run. The objective was successfully achieved where Repsol was able to set a new benchmark for the block, drilling the programmed depth of the well in 350 days, 17% less than AFE curve and 25% less compared with the best result in the block even with a significant change in lithology sequence from the program. The innovative 3DC technology boosted overall drilling performance. The new PowerDrive* rotary steerable system pads enabled the customized drill bit to drill farther and avoid unexpected bottomhole assembly (BHA) trips. The use of a new cutter block equipped with 3DC technology enhanced stability and reduced lateral displacement and vibration.

This paper explores four unique case studies where a novel limited-access ranging system was used in real world examples of well placement with close-proximity drilling applications. The case studies highlight enhanced recovery and reduced complexity for the overall well construction process. The method uses a gradient ranging system along with surface excitation to create an active magnetic field along the target wellbore to acquire a distance and direction measurement. This arrangement eliminates the need for the typical access-dependent ranging conveyance using coiled tubing or wireline systems. With this approach, several logistical and technical constraints are removed, making several unique solutions possible, such as ranging to abandoned wells and to wells with casing damage or other obstructions, and as well as high-temperature applications as no intervention is required to the target wellbore. The first case study used magnetic ranging to an abandoned wellbore in an approach similar to drilling a standard Steam Assisted Gravity Drainage (SAGD) injector well. The second study highlights an anti-collision scenario which required toe-to-heel ranging to an abandoned wellbore. The third used magnetic ranging as an anti-collision tool performing toe-to-heel ranging to a currently producing wellbore where completion tools were left in the hole. The fourth scenario used the technology to drill a parallel well where a casing and tubing obstruction limited the ability to run traditional ranging equipment. Through this paper, the authors will illustrate the benefits of this technology in their use in Steam Assisted Gravity Drainage drilling applications and expand on potential benefits of this technology in other close-proximity drilling applications for either paralleling or anti-collision purposes.

Flow assurance in ultra-deep waters oil production is always a major concern. Atlanta field, which produces heavy oil in ultra-deep waters, is one of the most challenging project offshore combining several difficulties: hydrates formation, emulsion tendency, scale formation, foaming, high viscosities that can achieve 100.000 cp at sea bed temperatures, etc. To overcome these challenges, the best subsea system technologies has been used, together with some small, but ingenuous, innovations. The use of a 6" unbonded flexible lines, with TEC 2 insulation layers minimize the risk high viscosities in case of the expected shut downs. To cope with scales, foaming and emulsion, chemical additives can be deployed into the wells through the biggest and unique umbilical installed in Brazil, which accommodates 15 hoses, 2 MV Electrical Cables of 3X150mm2 and 2 Eletrical Cables with 4x6mm2 and 2 eletrical cable of 4x2,5mm2. Hydrates can block the flowlines stopping the production. When it occurs, the remediation is normally long and expensive. For hydrates, the cliché "prevention is better than remediation" is true. Hydrates can be prevented with proper procedures and preventers. But in case of hydrate formation, a pioneer hydrate mitigation panel, operated by ROV was installed in the wet christmas tree (deployed by cables). And finally, to guarantee the production flexibility for production and maintenance, an innovative and unique subsea lay out, consisting of two Electrical Submersible Pump (ESP), one in-well and other in mud line skid, was developed and installed. All this innovations and best technologies used together made Atlanta a successful case of heavy oil production in ultra-deep waters, triggering huge resources around the world.

Primary cementing during well drilling operations aims, among other objectives, to provide structural stability by transferring well loads to surface formations, as well as being a safety barrier between casing and formation in order to prevent undesirable flow from permeable zones along the formation. The present work discusses whether permeable zones should be cemented along with impermeable zones, as degradation of cement quality has been observed in permeable zones due to, for example, circulation losses. According to API (2010), between 1960 and 1996, 6.5% of all primary barrier losses were related to problems with cementing. Thus, in this work we evaluate the quality of well primary cementing based on the hydraulic power developed during the cementing job, in order to discuss better cementing practices. In order to perform this analysis, data is collected from Santos basin in Brazil regarding cementing of production casings and liners in pre-salt wells, with 3 or 4 phases. Results show data collected from the drilling and cementing projects for selected wells, such as cement and cementing properties (density, volume, flow rate), casing properties (depth of casing shoes, diameter, weight), cement logging (expected vs. measured cement height, adherence quality of casing-cement and cement-formation), and drilling history (related operational problems). This data is then used to calculate the hydraulic power developed and to compare the quality of primary cementing between a 3-phase well, in which cementing is performed simultaneously in the impermeable (cap rock) and permeable (reservoir) zones, and a 4-phase well, in which the impermeable and permeable zones are cemented separately. Comparison between different wells allows us to verify our concerns regarding the quality of primary cementing in permeable zones, and to attest the quality of primary cementing as a barrier during the well life cycle. Usage of the developed hydraulic power to attest the quality of primary cementing based on field data is a novel approach as a quantitative methodology for assessing well integrity and safety, becoming a tool that aids decision-making during well design, such as in selecting the number of phases or choosing appropriate cementing procedures.

Extended reach horizontal wells face significant challenges in drilling longer laterals with oil-base mud (OBM). A novel solid-state lubricant was developed to close the gap in limitations of liquid lubricants and OBM with respect to lubricity in long extended lateral sections. The novel solid lubricant reduces the surface contact area between the asperities (deformations) by rolling and provides a chemically bonded film on the contact areas to reduce the amount of shear stress between the surfaces. There is limited understanding of the complex mechanisms affecting the coefficient of friction (COF). The principles of Tribology (the science of friction, lubrication and wear) were used to develop the solid-state lubricant. The Stribeck Curve describes the regimes while using a lubricant, including boundaries mixing elasto-hydrodynamic and hydrodynamic lubrication. Liquid lubricants are limited at controlling boundary conditions where the COF is ruled by asperities in contact between the surfaces. The novel solid-state lubricant works on the asperities of both the wellbore and bit/BHA. In addition, the COF is improved in the mixed and elasto-hydrodynamic lubrication regimes. Several oil-based mud field samples were tested for lubricity using different methods including the EP Lubricity Meter and Dynamic Lubricity Evaluation Monitor (LEM). The novel solid-state lubricant was also tested using a Tribometer to produce a continuous Stribeck curve that enables evaluation of the lubricant in the entire lubricity regime. The results of the COF using EP Lubricity Meter were transformed calculating the Stribeck number to build the curve. The potential benefits of the solid lubricant were discussed using a model developed by the Stick Slip vibrations with Stribeck curves. A reduction of COF in the boundary lubrication region occurs when the asperities of the wellbore and the bit/BHA are in contact. This is explained by the adsorption and absorption of the novel solid-state lubricant onto the asperities, providing a smooth surface. The novel solid-state lubricant has a wide particle distribution (PSD) to cover different size and height of asperities. The Stribeck curves of the novel solid-state lubricant show that the lubricant can reduce COF in the boundary lubrication region where friction forces are highest, compared with a base fluid and other liquid lubricants.

The geological evolution of the northern region of Colombia has resulted in lateral/oblique compressional stresses leading to the development of tilted faulted blocks and associated subsidence, followed by intense folding/uplift that has impacted the stress regime and the pore pressure evolution. Previous pore pressure prediction approaches often considered a shallow overpressure associated with a high fracture gradient (FG), and thereby allowing an assumption for a wide operational mud window. Drilling experiences however, indicated a contrasting scenario and thereby a better understanding and a more accurate estimation of overpressure and FG became necessary. With the aim of optimizing drilling operations, a geomechanics analysis was conducted, based on existing information incorporating local geological inputs and production well data, in order to better predict wellbore stability, pore pressure, fracture gradient and to identify related drilling risks for the planned wells. The resultant geomechanical model confirmed the presence of shallow overpressure development, the occurrence of which, along with its distribution and magnitude, is mainly controlled by the geological events (especially uplifting) that shaped the basin. Subsequent updates of the model managed to explain the frequent occurrences of water inflows, gas kicks, high volume of losses (a gain-loss situation) and instability recorded in previous wells. It also predicted a feasible but conservative mud weight window for the wells in this field. Understanding the geological evolution allowed for a better comprehension of the stress regime changes over time. Through an enhanced understanding of the geological and geomechanical influences, a risk mitigation strategy was developed to proactively reduce pore pressure and wellbore instability related drilling effects encountered in the earlier wells. So far, well schematics and mud weight windows have been optimized in five wells through utilizing this geomechanics approach to deal with the challenges imposed by a narrow mud window. The planned wells have been successfully drilled in record time with no major drilling problems by using the recommended mud pressures and optimized drilling practices.

When emergency situations in environmentally sensitive areas occur, drilling a relief well to intercept and kill the blowout well often requires various types of magnetic ranging technologies to navigate into the problematic well. Outside this scenario, we do not commonly hear about magnetic ranging. The main objective of this paper is to raise awareness among operators about magnetic ranging-while-drilling technology as wellbore placement service to make planned wellbore intersections to boost production. Reactivation of mature fields is often an economically viable option when demand for energy pushes oil prices upwards. In order to boost production from an existing mature field, an operator provided a service company with an interesting challenge: utilize proven directional drilling expertise in conjunction with alternative wellbore positioning techniques to drill two high-angle deviated wells from opposing directions and intercept a common vertical producer well for a gravity drainage concept. During the pre-planning phase, one of the major challenges was MWD survey accuracy for the horizontal wells. The 2-sigma major-axis uncertainty of the MWD surveys after applied corrections at the point of planned contact with the vertical producer was over 106 ft while the size of the target to intercept was only 1 ft in the lateral dimension. Implementation of magnetic ranging while drilling technology combined with north-seeking gyroscopic sensor allowed optimal positioning of all three wells relative to each other. Bottom hole assembly equipped with a smart mud motor, MWD, and magnetic bit-sub avoided collisions and steered successfully between other producing wells in the mature field. This challenging project from two opposite surface locations took several weeks of directional drilling and resulted in precise positioning both horizontal drainage sections within close proximity of vertical producer. Hydraulic communication with the vertical producer was successfully established from both horizontal wells after completion of the drilling operations.

With the increasing complexity of wells being drilled to optimally access as much of the reservoir as possible, an integrated drilling risk assessment strategy needs to be presented to address the increasing level of challenges and risks. Wells are being drilled deeper, through intervals that are heavily depleted into virgin, unexplored reservoirs. They are extending outward to horizontal lengths that were not even dreamed of several years ago. The assessment process described in this publication incorporates a better understanding of the complex geologic environment such as a multitude of pressure compartments, complex faulting and lithological variations that could potentially increase the risk magnitude. With these challenges, there is a step change in understanding and quantifying these hazards, risk liabilities and uncertainties that need to be addressed to make these projects commercially viable and be able to drill down to their designed targets without cost overruns due to NPT, and not less important, keeping a stable borehole capable of being evaluated and resulting in successful production rate. In order to address these challenges, more upfront in-depth planning and analysis must be performed. Often times, a review of the drilling issues are performed around symptoms of drilling events to respond to them, but not necessarily to determine why these events happened in the first place – the root cause. This shows when contingencies are built into a well plan to account for the NPT consequences of these drilling events observed in offset wells. In order to proactively address these increasing risks and hazards, development and incorporation of a detail risk mitigation strategy is required. Through experience, leveraging drilling, geomechanical and geological models in the risk assessment process, has proven to be successful in understanding the hazards that are present. Bringing out the potential hazards is just part of the strategy. A multi-discipline team needs to analyze each potential hazard and determine the best mitigation strategy to mitigate that risk down to a safe, acceptable level. The collaboration of a multi-discipline team is the key component to understand all the different drilling, geological, geomechanical and fluids influences on the potential hazard. With this type of approach in assessing the risk, the process can then address all the potentially different variables required to design an intelligent, proactive drilling strategy. Even with the best strategy in place, there are geologic uncertainties that still need to be analyzed. Knowing these uncertainties, this multi-discipline team designs a mitigation strategy utilizing the right mix of technologies and real-time monitoring component to be able to update models to fine-tune the drilling window and to provide recommendations while drilling - to optimize the drilling process. Showing that this process is effective, several results will be discussed, demonstrating the value of incorporating a pre-drill risk assessment along with real-time monitoring to reduce drilling time, uncertainties and to successfully provide safe and predictable operations from start to finish that provide ideal wellbore conditions for completion.

An automated system was developed to determine some physical properties of the drilling fluid in real time during drilling operations. Rheology, density, electrical stability, total solids suspended and water in oil ratio were determined in real time during onshore drilling operation. This work presented the results obtained using the system, comparing it with data obtained by standard offline methods according to API. The first stage of the development was performed in laboratory where the monitoring container was connected to a fluid flow loop was built. Rheology was determined using an inline modified concentric cylinder viscometer. The device was capable of determining shear stress at different shear rates. Density was determined by a Coriolis device, electrical stability was calculated by a self-designed device built under API technical design, water in oil ratio was provided by electromagnetic means of a commercial device and total solids suspended was calculated using a developed material balance equation, which uses real time data of density and water in oil ratio as inputs. The entire system was assembled into a skid, fully automated and controlled by in house developed software, adequate to be transported and installed at rig sites. The second stage was to test the system in onshore rig sites in northeast of Brazil. With automatic control of flow rate and pressure, the system performed measurements in the rig site drilling fluid, pumping the fluid in and out of the system, operating as a bypass of the main pressurized drilling fluid flow line. The system reported data locally on a screen and transmitted to a remote operations center. Density, electrical conductivity, total solids suspended and water in oil ratio were provided at every second. Viscosity profile was provided every 30 min with calculation at 6 different shear rates, in accordance to API. Electrical stability tests were performed every 30 min with 1 min of duration. The developed system performed measurements properly in the onshore rig sites. All technical requirements for operational safety were met, as well as environmental and electrical hazard managed. Overall statistical deviations calculated between online and offline reference data reported were considered satisfactory. The system constitutes the most complete project for real time fluid monitoring properties in real time. Several fluid properties (electrical stability, water oil ratios) were measured online for the first time. These properties are a requirement for real time diagnosis software and an essential input for autonomous drilling projects.

This paper presents a new approach based on a systematic workflow that diminish the uncertainties regarding heterogeneities and other geological factors that dramatically impact the unconventional reservoir performance in Vaca Muerta. In addition to the natural heterogeneities caused by marine depositional sub-environments that formed rock configuration variability, both vertically and horizontally, some areas of Vaca Muerta are affected by subsequent volcanic activity that creates complex characteristics for drilling and completions. A detailed geological, mineralogical and petrophysical characterization from the pilot well is performed to precisely determine landing points as well as the identification of traversed volcanic intrusive bodies. Pilot hole characterization added comprehensive knowledge to the horizontal drilling operations using Geosteering by decreasing geological uncertainty and allowing full control of drilling through the LWD azimuthal information in real time, and therefore making decisions to obtain optimal well placement. Critical information about elemental gamma ray spectroscopy (U / Th/ K, e.g.), that revealed specific reservoir characteristics of the depositional environment, supported the hypothesis of the heterogeneity of Vaca Muerta Formation and helped to identify the intrusive bodies. The workflow is completed with a complete structural evaluation, identification of natural fractures and textures from electrical borehole images logged in Oil-based mud environment. This analysis defined precisely the intrusive (dikes and sills) configurations. Textural and mineralogical characteristics, as well as information about their location, spatial and relative geometric development are included in the evaluation. The analysis provided critical inputs for completion decisions as well. Operational and evaluation results are used as the platform for future developments of new exploratory non-conventional areas.

A water flooding project was initiated in a mature field in the Oriente basin. The shortage of water production for the implementation required the identification of the water source, an infinite aquifer located at the base of existing wells. Next, well integrity, well schematics, well status, water quality and water demand were used to define the best candidates to be converted from oil producers to water source wells. As part of the operational process several issues were solved by the evaluation and implementation of different solutions. To isolate shallower producing intervals, three technologies were applied: traditional cement squeeze, scabliner and casing patch. The latter resulted to be the best technical solution followed by scab liner and cement squeeze. To avoid residual oil zones at the top of the water source reservoir, it was necessary to create a new operative bottom by drilling out cement, landing collars and float collars at the base of the production liner or casing. As the well productivity index of the water source wells ranges from 8 to 80 BPD/psi and the reservoir pressure is steady at 4,500 psi, electrical submersible pumps are installed in the 9 5/8 production casing at shallow depths. This configuration reduces operational risks and provides the required discharge pressures to reach the injection points. Over the course of the project the perforated interval for water production was continuously optimized, as pressure and water viscosity are mostly constant, and the absolute permeability is quite homogeneous. These water source solutions proved to be successful for the first phase of the waterflooding project and were extrapolated to other areas of the asset resulting in 16 wells being converted to water source wells, and 3 wells being recompleted as dump flooding wells. This document can be used as a guide and set of best practices for recompleting wells to produce high quality water from existing wells by integrating reservoir conditions, mechanical configurations and water demand requirements. The analysis of NPT and UPT will also provide additional clues for converting oil producers to water source wells.

The objective of this paper is to present the improvement in zonal isolation and cement sheath properties using foam cement in heavy oil Chichimene Field in Colombia. Achieving complete zonal isolation in the pay zone have become a major challenge in these fields, recently, given the complexity of the reservoirs: high permeability, low pressure, highly fractured, depleted, low fracture gradient, and cement column for well integrity. Despite advances in drilling technologies, such as MPD, massive losses still represent a major risk both drilling and cementing. Using commonly known cementing methods, like stage tool cementing and conventional slurries, have led to fair results. Foam cement technology emerged as an appropriate cementing method given its great properties both being pumped down, and once set Foam cement has several advantages over conventional methods: it prevents losses, enhances displacement efficiency in the annulus, provides a unique feature of density/strength ratio, and has improved resilience and elastic properties once set. Production liners in Chichimene and Castilla field have been cemented successfully with foam cement, even under severe well conditions as partial to severe losses. Full returns have been observed in all jobs while cementing, and cement has been seen at surface after circulating fluids out of top of liner. Good isolation has been obtained as per cement log evaluation. Foam cement has proved to be effective cement method to achieve proper isolation in difficult wellbores and has been of great benefit for cementing production zones in the mentioned fields. Novelty of the cementing process, described herein, delivers unique engineered features that have proven a major benefit to ensure well integrity in the fields. Cementing under critical wellbore conditions, still account for many costly remedial works, and this novel approach for cementing showed its benefits to achieve excellent results. Content of this paper could benefit many operators dealing with critical wellbores.

An integral aspect of field development planning is the process of identifying remaining, feasible, and actionable field development opportunities (FDOs) such as recompletions and new drills. In mature brown fields, this process is extremely difficult to undertake in a reasonable timeframe due to the sheer size of the available datasets (e.g., thousands of wells, decades of production history), geologic complexity (e.g., dozens of layers, faulting, folding, fractures, pinchouts), and engineering challenges (e.g., commingled production and injection, field compartmentalization) unique to each reservoir. The automated framework is a fully streamlined framework that aims at building a comprehensive opportunity inventory consisting of behind-pipe recompletion opportunities, vertical new drill locations, sidetrack opportunities, and optimal deviated/horizontal targets. In addition to opportunity identification, it can generate additional deliverables for vetting purposes including a well book report and a standardized Petrel project. The main objective of this process includes: 1) fast, data-driven, and consistent approach for evaluating and identifying field development opportunities, 2) fast execution time, accelerating processes from months to days, 3) integration of multi-disciplinary data, 4) consistency and repeatability, minimizing subjectivity, and 5) streamlined visuals for opportunity vetting. This framework has been successfully applied to a mature field in the Middle East with more than 1,000 producers and 55 years of production history. Hundreds of recompletion opportunities were initially identified for the field. A final list of opportunities is then generated by running the opportunities through a series of user-provided attribute filters such as minimum initial rate, minimum oil thickness, maximum acceptable uncertainty, and so on. The process is then typically finalized with manual vetting of the opportunities by subject matter experts including geologists, reservoir engineers, and production engineers that ensure the opportunities are geologically sound, mechanically feasible, and meet various validation criteria that are discussed in this document. A final list identified 116 recompletion opportunities in 116 wells with a total potential production upside of around 63,000 B/D.