bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study of Unconventional Gas-Well Fracturing in Hungary
Authors: Shaoul Josef R. , Spitzer Winston , Dahan Matthew W.
Published: April 2012

Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones, and the expected permeabilities were in the range of 0.001 to 0.5 md. Two hydraulic-fracture treatments were performed. The first fracture treatment was in the lower part, and the second treatment was in the upper part of the deepest interval. With no previous propped-fracturing experience in this field, the first treatment was designed as a conventional crosslinked-gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 md. Because of lower-than-expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the second fracture treatment was changed to a water-fracture design. This formation clearly falls into the unconventional category, and consequently was a good candidate for a water fracture.

This paper describes the prefracture diagnostics, fracture execution, and post-fracture production evaluation of this unconventional gas well. Special emphasis is placed on the use of small-volume injection tests, or diagnostic fracture injection tests (DFITs), to obtain an estimate of the in-situ kh because it is impossible to perform prefracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the postfracture well-test analysis in a numerical-simulation model that includes fracture-filtrate-cleanup modeling. Post-fracture analysis showed that the initial proppant-pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked-gel treatment was not able to clean up effectively, and therefore showed limited stimulation effectiveness. The first-ever water fracture in a gas reservoir performed in Europe showed a more significant production improvement during the short post-fracture test. The results from this well suggest that, as in North America, water fractures appear to have better initial production than crosslinked-gel fractures because of better fracture cleanup in European reservoirs with microdarcy permeability.
A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Rate Boundary Condition
Authors: Nobakht Morteza , Clarkson C.R.. R.
Published: April 2012

Hydraulically fractured vertical and horizontal wells completed in shale gas and some tight gas plays are known to exhibit long periods of linear flow. Recently, techniques for analyzing this flow period using (normalized) production data have been put forth, but there are known errors associated with the analysis. In this paper, linear flow from fractured wells completed in tight/shale gas reservoirs subject to a constant-production-rate constraint is studied. We show analytically that the square-root-of-time plot (a plot of rate-normalized pressure vs. square root of time that is commonly used to interpret linear flow) depends on the production rate. We also show that depending on production rate, the square-root-of-time plot may not be a straight line during linear flow; the higher the production rate, the earlier in time the plot deviates from the expected straight line. This deviation creates error in the analysis, especially for flow-regime identification. To address this issue, a new analytical method is developed for analyzing linear-flow data for the constant-gas-rate production constraint. The method is then validated using a number of numerically simulated cases. As expected, on the basis of the analytical derivation, the square-root-of-time plots for these cases depend on gas-production rate and, for some cases, the plot does not appear as a straight line during linear flow. Finally, we found that there is excellent agreement between the fracture half-lengths obtained using this method and the input fracture half-lengths entered in to numerical simulation.
Advanced Upscaling for Kashagan Reservoir Modeling
Authors: Panfili P.. , Cominelli A.. , Calabrese M.. , Albertini C.. , Savitskiy A.. , Leoni G..
Published: April 2012

The Kashagan field is a huge carbonate formation located 4.5 km below the bottom of the North Caspian sea. The reservoir is saturated by overpressured light oil, and the development is based on first-contact-miscible gas injection.

The reservoir is highly stratified, with a fine sequence of depositional cycles and long-range lateral correlations. Three porosity systems (matrix, karst, and fractures) can be organized in two main environments: a massive, low-permeability, matrix-like inner platform and a highly fractured/karstified rim.

The reservoir geology is modeled by means of detailed geological grids consisting of tens of millions of cells, with vertical spacing of 1 m or even less to account for high-order depositional cycles. Geological grid cannot be used to run compositional simulations, and much-coarser grids, in which hundreds of geological layers are lumped in few tens of dynamic layers, are used by reservoir engineers. To minimize coarse-scale errors, an average lateral spacing of 250×250 m is used for both simulation and geological grid; nonetheless, upscaling remains a challenge. Traditional permeability (k*) upscaling methods, including flow-based methods, overestimate Kashagan field/wells production and injection potentials.

We implemented a method in which the outcome of the upscaling is effective transmissibility (T*) instead of k*. T* upscaling has been proposed in the past as an alternative to k* upscaling, but it is neither part of commercial workflows nor widely accepted in the reservoir-modeling community. In our T* upscaling, the solution of local flow problems around coarse-cell interfaces is used to compute coarse transmissibility. T* and k* upscaling were compared by simulating both single-phase and gas-injection problems, including platform and rim, using the results of fine-scale simulation as a reference. We considered (1) single-porosity simulations with geological grid populated by only matrix (first medium) and karst+fracture (second medium) properties and (2) dual-porosity/ dual-permeability simulations encompassing both media. Contrary to k* upscaling, T*-based coarse simulations perfectly replicate fine-scale field and well injection/production potentials.

Using T* upscaling as a cornerstone for company activities on Kashagan, we can run coarse-scale full-field simulations in a few hours without loss of consistency with the results provided by weeks-long, often unpractical, fine-scale simulations. On the contrary, the inaccuracy of k* upscaling would have required much finer and more computationally-expensive simulation grids together with the implementation of ad hoc multiphase upscaling.
Fracture and Fatigue of Polycrystalline-Diamond Compacts
Authors: Zacny K..
Published: April 2012

Four different batches of polycrystalline-diamond compacts (PDCs) were tested under monotonic and cyclic loadings. Initially, the mean load to fracture was recorded for each batch. In fatigue tests, the specimens were preloaded to between 75 and 95% of a batch mean static (S) strength and the R-ratio of 0.1 was used with frequencies of 10 and 20 Hz. It was found that some PDCs sustained greater than 106 cycles without fracturing. It was also noted that fracture force was reduced by 10 to 35% after the specimens were subjected to cyclic loading. This could indicate that fatigue weakens the structure of the PDC material. Tests conducted on two opposing edges of the same PDC buttons showed that the fracture on one side does not affect the strength of the opposing side. Thus, PDCs whose fracture or wear on flat areas is relatively small can be salvaged from the old bits, rotated 180°, and then rebrazed. Investigation of the fracture surface using a scanning-electron microscope (SEM) revealed that the fracture followed a transgranular path.
Best Practices for Conducting CO2-EOR Lab Study
Authors: Al-Otaibi Fawaz M. , Al-Mutairi Saad M. , Kokal Sunil L. , Funk James J. , Al-Qahtani Jassi F.
Published: April 2012

Energy demand has been escalating and is predicted to increase further in the coming decades. The dialogue on global climate change has the world abuzz on the primary green house gas, carbon dioxide. Both of these factors have created a perfect storm for the use of carbon dioxide for enhanced oil recovery. The petroleum industry is ideally suited for disposing of this green house gas. Each oil company (and others) has therefore stepped up its efforts in carbon dioxide utilization, either for EOR or sequestration. The injection of CO2 into a reservoir is not new. Indeed CO2 injection has established itself as a very efficient mechanism for increasing oil recovery.

To design a CO2-EOR or CO2 sequestration project, one requires a large set of appropriate experimental data for a given reservoir/fluid system. Where does one start? Even if the data have to be generated in a service lab, a good design requires some thought and effort. A search of the literature reveals no best practices for generating this dataset. This paper presents a comprehensive experimental design for conducting a CO2 laboratory study.

The essential components of a laboratory study for CO2 injection include measuring fluid-fluid interactions and fluid-rock interactions. Fluid-fluid studies include miscible displacement tests, measurement of minimum miscibility pressures, fluid properties of CO2-oil or CO2-brine mixtures including viscosity and density, asphaltene precipitation, and swelling. Fluid-rock interaction studies typically include coreflooding tests for determining the oil recovery potential, three-phase relative permeability, critical gas saturation, gas trapping and wettability changes. Each of these sets of experiments will be described in light of their best practice. The ultimate goal is to establish a procedure for generating a reliable and accurate dataset.
Modification to Equations of Gas Flow through Choke
Authors: Ling K.
Published: April 2012

Chokes are used to limit production rates to meet sale contract, comply with regulations, protect surface equipment from wearing out, avoid sand problems due to high drawdown, and control flow rate limited by capacity of the facility. Single gas phase flow through choke is vital to oil industry because not only an accurate estimation of gas flow rate guarantees a reliable supply to the end users, thus the predictable revenue from gas sale for the company, but also protect the equipment from breaking as a result of high gas rate. Nevertheless, importance of gas metering cannot be overemphasized. Gas flow through choke had been studied by numerous investigators, Different choke flow models are available from the literature, and they have to be chosen based on the flow regimes, that is, subsonic or sonic flow. The most common used flow equations developed by Shapiro, Zucrow and Hofmann are used for subsonic and sonic flow, respectively. Sonic flow happens when downstream to upstream pressure ratio is equal to critical pressure ratio.

A careful review of these equations indicated that they are not theoretically rigorous and give inaccurate gas flow rate for the real gas. Thus these equations need to be modified in order to be used to calculate gas flow rate under both flow regimes. After a thoroughly analysis and derivation we came up with equations that have solid base. New correlations that reconcile the issue caused by approximation method used to derive the old gas flow equations were based on both engineering judgment and physical phenomenon. The error in the old equation can be corrected with the new equations. New equations provide good approaches to quantify gas flow through choke.
Drift-Velocity Closure Relationships for Slug Two-Phase High-Viscosity Oil Flow in Pipes
Authors: Jeyachandra B.C.. C. , Gokcal B.. , Al-Sarkhi A.. , Sarica C.. , Sharma A.K.. K.
Published: April 2012

The drift velocity of a gas bubble penetrating into a stagnant liquid is investigated experimentally in this paper. It is part of the translational slug velocity. The existing equations for the drift velocity are either developed by using the results of Benjamin (1968) analysis assuming inviscid fluid flow or correlated using air/water data. Effects of surface tension and viscosity usually are neglected. However, the drift velocity is expected to be affected by high oil viscosity. In this study, the work of Gokcal et al. (2009) has been extended for different pipe diameters and viscosity range. The effects of high oil viscosity and pipe diameter on drift velocity for horizontal and upward-inclined pipes are investigated. The experiments are performed on a flow loop with a test section with 50.8-, 76.2-, and 152.4-mm inside diameter (ID) for inclination angles of 0 to 90°. Water and viscous oil are used as test fluids. New correlation for drift velocity in horizontal pipes of different diameters and liquid viscosities is developed on the basis of experimental data. A new drift-velocity model/approach are proposed for high oil viscosity, valid for inclined pipes inclined from horizontal to vertical. The proposed comprehensive closure relationships are expected to improve the performance of two-phase-flow models for high-viscosity oils in the slug flow regime.
Using Cogeneration To Mitigate CO2 Emissions in Upstream Oil & Gas Activities
Authors: Welch M. J.
Published: April 2012

The production of oil and gas, and the various processes required to make these products suitable for transportation, is an energy-intensive operation. Provision of electrical power, process heat and mechanical power usually requires the combustion of fossil fuels with resultant CO2 emissions to atmosphere. Flaring of hydrocarbon-based waste gases also creates additional CO2 emissions at production facilities.

In many instances, taking a more global approach to facility design can greatly improve energy efficiency and hence reduce CO2 emissions. Employing Cogeneration technologies to generate both power and heat, or to recover waste heat from processes to generate electricity, can both reduce site emissions and help ensure security of electricity supply. It may also be possible to use waste-gas streams as a fuel for a Cogeneration plant, reducing the amount of premium fuel required and simultaneously eliminating gas flaring, or to sell any surplus electricity generated, turning a waste into a potential revenue stream.

There are numerous ways to configure a Cogeneration plant, depending on the ratio between the power and the heat required by the facility, the available fuels or waste heat sources, the form of process heat required and the actual electrical power demand. This paper will examine some of the different well-proven potential Cogeneration configurations based on Gas Turbines, Steam Turbines and Gas Engines, as well as looking at how the newer technologies of Organic Rankine Cycles and Concentrated Solar Power can be employed in Cogeneration applications.

With potential overall fuel efficiencies in excess of 75%, Cogeneration can offer significant CO2 reduction over separate generation of power and heat, from either an on-site or off-site facility, or imported power from a remote third-party power plant. The paper will discuss potential CO2 savings for certain common plant configurations and fuels.
Enhanced Drilling Solution for Top-Hole Sections on Jack up Wells with Environmentally-Improved Method and Dual Gradient Drilling Techniques
Authors: Scanlon T. , Medeiros F.
Published: April 2012

This paper describes the design and use of a subsea pumping system that allows improved construction of top-hole sections on offshore, jack up-drilled wells. This system has now been used for the first time offshore Brasil with positive results.

This subsea pumping system - the RMR™ (Riserless Mud Recovery) System - has been used extensively in other areas of the world, primarily on floater-drilled wells (Stave et al., 2005; Smith et al., 2010; Cohen et al., 2010, Scanlon, 2011). This previous RMR experience coupled with detailed discussions with Petrobras in Brasil resulted in this modified design for use on jack up-drilled wells, offshore Brasil.

Petrobras has a number of wells to drill in shallow waters offshore Brasil and needs a system that provides for minimal discharge of cuttings and drilling fluids to the ocean environment during drilling and installation of the conductor string, and that also enables better management of bottom hole pressure, when drilling the next hole section, inside the conductor string.

This new version of the RMR system has now been deployed offshore Brasil on two Petrobras wells. The system collected drilling fluids from the top hole section and pumped them back to the rig successfully, thus reducing the amount of cuttings and drilling fluids released into the natural ocean environment. The system was then used, after installation of the conductor string, to provide dual gradient drilling (DGD) techniques in the next hole section (for surface casing), resulting in improved penetration rates and well bore stability below the conductor shoe.

The RMR system used is described in this paper as well as the operational experiences realized on the first two wells and the improvements being made to prepare the RMR system and techniques for additional wells.
Fractional Flow in Radial Flow System—A Study for Peripheral Waterflood
Authors: Ling K.
Published: April 2012

The famous Buckley-Leverett displacement mechanism has been used to predict the performance of waterflood. With Buckley-Leverett method, oil recovery from waterflood is calculated and required water injection volume to achieve that oil recovery is estimated. This method does provide a very useful tool in waterflood design. Our experience in oil industry and a thorough literature review indicates that petroleum engineers used Buckley-Leverett method to analysis waterflood project directly without any adjustment basing on the real reservoir and production situations. By doing so, a lot of errors are introduced into the analysis.

It should be noted that Buckley-Leverett method assumed displacement occurs in a linear system. This is true for some waterflood scenarios while for others it is not. For some waterflood scenarios a radial system is more appropriate than a linear system. In this study we investigated the fractional flow in a radial system and derived the solutions to predict the performance of water displacing oil in radial system. With this radial displacement model, design and prediction of waterflood can be achieved by Buckley-Leverett method or our model, whichever fits the waterflood pattern. Considering the fact that many waterflood scenarios follow radial displacement, our model is an important supplement to Buckley-Leverett method.
Process Environmental Remediation Liabilities, Northern Region
Authors: Ventura Perez Jose Angel
Published: April 2012

Process describes the Environmental Remediation Liabilities (Dams and Contaminated Land), which was carried out in PEP Northern Region, which has optimized the process of identification, characterization and implemented best practices in remediation of soil, paying off in better performance environmental, and under budget year to the enforcement of environmental regulations.

The work was created in four stages: identification, to specify location and census, Characterization, which defined the terms and scope of characterization, developed an agreement with technical and economical choice to have a comprehensive characterization of contaminated sites hydrocarbons (environmental liabilities), reducing the uncertainty for the remediation, remediation, with the selection of sustainable methodologies and with less impact, and Management, to regulate all activities. The results, main, were:

We defined the requirements for a comprehensive characterization of the site.

We obtained a 27% savings in Dams and 80% in soils in the selected proposal.

Was determined with greater accuracy, surface and volume to remedy, providing certainty to the census of contaminated sites

We have characterized 140 dams and 148 hectares of contaminated land

We identified 92 dams and 2.84 ha, which do not require remediation for the characterization values within standard registration.

In the remediation, sustainable techniques were selected as co-processing, chemical oxidation and bioremediation, obtaining the remediation in the period 2010-2011, 262 dams and 83.29 hectares of environmental liabilities.

186 Management of remediation programs at the SEMARNAT DGGIMAR of which 99 have been resolute.
BC-10: The First Successful Replacements of Caisson ESPs in Deepwater Brazil
Authors: Harris D. , Bode W. , Martinez I. , Rivera R. , Hines Natalya
Published: April 2012

The Parque das Conchas development is located in the BC-10 block 75 miles southeast of Vitoria int the Campos Basin, offshore Brazil. Shell is the operator with a 50% equity share, with joint venture partners Petrobras (35%) and ONGC (15%). The current development consists of three hydrostatically pressurized medium to heavy oil reservoirs (Abalone, Ostra and Argonauta B West) in water depths ranging from 5430 ft to 6310 ft (1655 m to 1923 m). One of the key enabling technologies at the heart of the subsea system infrastructure is the mudline boosting system consisting of Modulo de Bombeio or Pumping Unit (MOBO) caisson ESPs installed inside Artificial Lift Manifolds (ALMs) 1). Oil from the individual subsea wells flows into the MOBO caisson ESPs and from there the ESPs pump the oil up to the floating production, storage and offloading (FPSO) vessel. The ALMs are located approximately 5½ miles (8.85 km) from the FPSO (see Figs. 1 and 2).

This paper will describe how the design for these special longlife ESPs was developed, how a stack-up test was performed on land in the US, and how the pumps were deployed in the field. In the second part, the first operations for pulling two of the ESPs are described. The whole assembly consisting of the MOBO, 32-in. caisson and ESP completion was lifted in open water to the rig with a total assembled weight of 169 tons (171.7 metric tons).
A New Numerical and Analytical Approach for Determining Formation Fluid-Sample Clean-up Behavior through Multiple Sensor Analysis
Authors: Eyuboglu S. , Proett M. , Gao L. , Sliman W. , Senne R. , Pedigo B. , Engelman B.
Published: April 2012

The accurate determination of fluid properties and contamination while sampling with a wireline pump-out formation tester is essential to achieve the primary objective of obtaining representative reservoir fluid samples with minimum rig time. Despite advancements in fluid identification sensors, sampling in mixed phases, especially immiscible fluids, still poses a great challenge. It often happens that apparent erratic sensor responses are attributed to sensor noise, but careful study reveals that the sensors are actually showing the true nature of the multi-phase fluid flow. However, if this multi-phase behavior is not considered, it can be difficult to determine fluid type and contamination. This work addresses the development of a new numerical and analytical investigation that makes it possible to not only understand the cleaning behavior of formation fluids but also quantitatively determine fluid qualities in real time. This newly developed technique highlights the variables that play an important role in guiding the clean-up process and, at the same time, provides the temporal characteristics of the contamination level versus both time and fluid volume. Furthermore, uncertainties in the pumping time required to achieve the desired level of contamination are also calculated with this method. Field examples from Gulf of Mexico, South America and North Sea are provided to demonstrate the efficiency of this technique in oil-based mud and water-based mud contamination examples for both hydrocarbon fluid and formation water samples, with comparisons to PVT laboratory measurements. An error analysis is performed for each example, and results are presented in this research.

The new analysis technique is applied to a high-resolution fluid density sensor that monitors the change of resonance frequency of a vibrating tube-carrying fluid sample. The same interpretation method is also applied to a capacitance sensor and a resistivity sensor to further confirm the results derived from the density sensor.
Enhancing the Effectiveness of Workover Interventions with Coiled Tubing and Real-Time Downhole Measurements
Authors: Franco Ernesto , Molero Nestor , Gerardo Miguel , Nevarez Cesar , Martinez Arturo , Marin Eric , Pérez José
Published: April 2012

In offshore Mexico, operators have increased workover activity to maintain oil and gas production. The reservoir is a naturally fractured carbonate with gas and water flowing through the natural fractures, leaving oil trapped in the matrix. Controlling gas and water production is critical to prevent unwanted fluid from reaching the wellbore.

Currently the combined progression of gas and water contacts has reduced the oil window from several hundred to as little as 40 m in some wells. In these conditions, and with rapidly advancing gas and water contacts, it is paramount to provide solutions to restrain unwanted fluid from reaching the wellbore.

One of the most common workover interventions consists of isolating the water producing zone with coiled tubing deployed through-tubing inflatable-packers (CTD-TTIP) and perforating an upper oil-bearing zone. The problem is compounded by low reservoir pressure, resulting in heavy losses while drilling and cementing production zones; loss of zonal isolation as result of cement sheet failure through the producing intervals; and wells completed with a combination of large tubular sizes.

Recently, operators and service companies in offshore Mexico have implemented an innovative workflow intended to enhance the effectiveness of water control interventions in this challenging work environment, through the utilization of realtime downhole measurements (RTDM) via coiled tubing equipped with optical fibers (CT-EOF) for accurate control of CT depth, the packer inflation process, packer differential pressure limits during the treatment injection, and fluid placement.

This paper provides a technical analysis of the engineering process required to develop successful workover zonal isolation jobs with CTD-TTIP and RTDM in offshore Mexico, and presents a case history, lessons learned, conclusions, and recommendations from the experiences gained while performing CTD-TTIP with RTDM in offshore Mexico.
Calculation of Gearbox Torques of Rotaflex Pumping Units Considering the Elasticity of the Load Belt
Authors: Takacs G. , Chokshi R.
Published: April 2012

One of the most successful long-stroke pumping units available today is the Rotaflex, a completely mechanical device. Its construction is entirely different from the traditional beam pump mechanisms and has polished rod stroke lengths up to 366 in. Due to the low pumping speeds required and the special geometrical arrangement Rotaflex units require significantly less torque than beam pumping units and provide several other advantages over those.

The unit's most important component is a uni-directionally rotating roller chain connected to the polished rod through an elastic load belt. The kinematic behavior of the chain, running on two sprockets is relatively simple to describe; the paper presents exact formulae for the calculation of polished rod position, velocity, acceleration, and torque factor functions. The recommended formulae provide a theoretically sound description of the unit's kinematic behavior and can serve a sound basis for the calculation of gearbox torques for cases when load belt stretch is neglected.

Prior publications on Rotaflex operations relied on the assumption of a rigid load belt and determined the loading of the gearbox accordingly; field practice, however, indicates considerable stretch in the elastic belt. The paper, for the first time, presents a thorough investigation of the kinematic performance of Rotaflex pumping units with due consideration of belt stretch. The effect of operational stretch due to polished rod load on gearbox torques and the energy conditions of Rotaflex units is investigated through several example problems.
Workflow Automation (WFA) for the Integrated Production Operations in the Macuspana Field
Authors: Villanueva C. Cruz , Tapia C. , Calatayud A. , Benumea M. , García A. , Hernandez V. H. , Balcazar J. A. , Lotar T. , Purwar S. , Rodríguez J.
Published: April 2012

Workflow automation (WFA) is a key element for integrated production operations in oil and gas assets. Identification, analysis, optimization, and automation of workflows enable a integrated and cross-disciplinary vision of the asset and in consequence, enable a more timely and accurate decision making process.

This paper describes the production management workflow optimization and automation for the Pemex Macuspana asset, which is an onshore asset located in Tabasco, Mexico. This paper describes how an adequate integration between processes, people, and technology enables operational goals to be reached within a short period of time.

The Macuspana asset has more than 100 production wells and a complex surface network, which is interconnected with other Pemex production assets. To optimize and automate the production management workflows of this asset, a complete workflow automation solution was implemented, which includes a common web environment enabling data capture, validation, and visualization. It also includes a workflow orchestration engine for integration with engineering applications, optimization, and automation of production operations processes. As part of the implementation, the following activities were completed: Automatic calculation of production volumes on a daily basis using well and network modelsWell test validation workflow incorporating well model update and operational constraintsForward simulation and back allocation engines to automatically distribute production volumes

After deployment, the solution enabled teams across various disciplines to collaborate and to analyze production estimates and asset performance more accurately, minimizing production losses. The solution delivered is the first important step of the Macuspana asset toward the implementation of its digital oilfield (DOF) initiative.
GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics
Authors: Restrepo A. , Ocampo A. , Lopera S. , Diaz M. , Clavijo J. , Marin J.
Published: April 2012

Well stimulation for production or injection enhancement in mature fields is a key and challenging task. Loss of reservoir energy due to pressure depletion coupled with complex damage scenarios existing in adverse petro physical environments can become restrictive factors for the proper performance of conventional liquid based chemical stimulation systems. Main limitations are normally related to high interfacial tensions preventing optimal well's clean up and cost-effective achievable penetrations. This work presents a new well stimulation concept in which the carrying system is gas instead of liquid. The overall study will be presented in 2 parts. Part I will discuss basic physical questions related to treatment durability as a function of deployment method (continuous dispersion vs liquid batch gas displacement) for at least two damage scenarios of particular interest: asphaltene deposition and condensate blockage. A basic mechanistic simulation is also presented for benefit estimations at well scale. Part II will focus on field trials design and execution using micellar and/or fluoropolymer type of chemistries that exhibited the best performance when tested under laboratory conditions.

Experiments herein presented were done in formation sandstone cores simulating reservoir conditions. It is shown that natural gas when used as the carrying system to deploy conventional asphaltene dissolution and condensate removal chemistries enhances both Ko re-establishment and treatment durability as compared to equivalent liquid-based applications. Additional studies are being performed to maximize the effectiveness of the GaStim concept. Sensibilities to gas type (N2, CO2), added chemical and dosages as long as field trial documentation will be presented in part II of the present work.

GaStim concept is presented as a novel chemical stimulation technique potentially allowing deeper penetrations and better chemical adsorptions. Its potential, although still not fully undiscovered, is certainly supported by higher Ko reestablishment values and longer treatment durabilities observed.
Stimulation in Wells with Electric Submergible Pumps Increases Production and Save Costs without Damaging Pumps
Authors: Gallegos M. , Milne A. , Del Rio C. , Robles M.
Published: April 2012

Stimulating sandstone formations typically requires a mixture of hydrochloric acid (HCl) and hydrofluoric acid (HF) to dissolve formation damaging minerals. The HF reacts with and dissolves all HCl soluble minerals and, dissolves or partially dissolves siliceous materials such as bentonite and naturally occurring formation clays. Because these acid treatments are corrosive, it is common practice in low-pressure wells to pull out the electrical submersible pumps (ESPs) prior to performing a stimulation treatment to prevent damage to them. Doing so results in additional costs and deferred production.

In Ecuador, oil is produced from low- pressure sandstone reservoirs by using ESPs. In many of these reservoirs production is limited by scaling or fines migration. The low reservoir pressure often results in additional formation damage when during workovers because of the loss of completion fluid, emulsions, and clay instability. Many operators prefer to produce well with formation damage rather than expose the ESPs to corrosive fluids to remove the damage or generate additionally damage during a workover.

Using a non-acid chelating system (NACS) as the stimulation fluid combined with a placement technique made it possible to stimulate wells completed with ESPs or with corrosion sensitive completions, without needing to pull out the ESP for the stimulation treatment.

A laboratory study to assess the corrosion of each component of an ESP exposed to different treating fluids (live and spent) for extended periods was undertaken. The NACS fluid was capable of both removing calcium scales and fines, and preventing fines migration while minimizng corrsoion.

The NACS stimulation fluid successfully treated more than 10 wells competed with ESPs. In many cases, production in these wells increased by 35%. In addition, the treatment cost was 70% less than treatments for which a workover rig was used. Moreover, deferred production was reduced from days to hours.

Because of the time and cost savings, this technique should be particularly beneficial in marginal fields, where rig availability and economics are often an issue.
Artificial Communication Between Compartmentalized Reservoirs to Maximize the Value with Existing Infrastructure in Offshore Fields
Authors: Martinez V. , Ascencio F. C. , Ley H. Cinco , Lozada M.
Published: April 2012

This paper aims a solution to improve dynamic connectivity between regions in compartmentalized reservoirs. The proposal is to drill horizontal wells whose main objective is to communicate the zones where compartmentalization has been detected. The fluid flow between compartments will occur due to the potential difference existing between them. The flowrate will depend on the petrophysical properties of reservoir, physicochemical properties of fluids and the design of horizontal well. The work develops a mathematical model that represents the potential behavior of each compartment over time when they are communicated through a horizontal well. It considers the special application for gas cap systems and it presents an example, which demonstrates the impact and benefits of this solution. The implementation of this proposal will help exploiting the hydrocarbons reservoir through the existing infrastructure in adjacent regions, thus, reducing or eliminating the requirement of new infrastructure and extending the lifespan of existing infrastructure, thereby maximizing the value and recovery of the fields, which can represent great economic benefits for many oil companies.
Enhance Platform Integrity by a Real-time Equipment Availability Monitoring Workflow
Authors: Machado L. , Costa M. , Correa S. , Regina E. , Herdeiro M.
Published: April 2012

One of the greatest strategic focuses of the oil industry is the maintenance area, which is directly responsible for the availability of equipment involved in the production process. It affects the platform operational efficiency and consequently, the company results. Those results will increase with increases in effective maintenance management. In addition, the oil industry has experienced a wave of process optimization and systematization through new tools that support management and decision-making processes.

This paper presents a workflow that enables remote monitoring of onboard equipment status (operating, stand-by, or unavailable), identification of equipment with elevated risk of target violations, and the calculation and analysis of availability indicators. It also provides access to the historical data of unavailability events for the equipment monitored. This workflow performs real-time equipment monitoring through several logic implementations using sensor signals, automatically recording events at the moment that the equipment shows to be unavailable, and sending alerts to personnel responsible for the equipment. In addition, some equipment that do not have sensor signals, which enables real-time monitoring, were included in the daily routine through a manual process of entering unavailability events in the system enabling a further analysis of the historical unavailability. Consequently, the availability indicator is calculated in real time on the basis of these unavailability events. During the monthly indicator consolidation process, the system generates a report of the equipment that functioned below the set target, enabling a focus on the treatment of the most critical equipment during maintenance and asset integrity meetings.

The workflow solution provides several benefits. First, it monitors the status of equipment in real time, enabling a faster return to normality. It also captures unavailability events automatically, and records and provides details about these events. The workflow also monitors availability indicators, monitors major unavailability events by exception and historical analyses, and ensures the integrity of the process plant.
Decision-Making Breakthrough Technology
Authors: Fernandez Damian A. , Vidal Matias J. , Festini Diego E.
Published: April 2012

Nowadays the industry requires higher operational efficiency and reservoir management optimization. It is essencial for making decisions to have information in a timely and integral manner.

The objective of this report is to demonstrate how the use of surveillance together with specific well management software came to be an important tool to take more accurate and faster decisions. It provides access to real time events and data, and also makes it easier to have an efficient and cooperative interaction between people in different areas, optimizing the task flow. This research describes the hardware and software components of the surveillance system and analyzes how the different modules of the management software work.

The results show how minimizing downtime through early events detection increased production and how the efficient use of resources reduced the lifting cost. This all translates to a better operational organization and makes it possible to act proactively by identifying potential problems or failures in wells.

In conclusion, having a digitalized oil field allows us to reach agreement easily and to concentrate efforts in solving problems, through the close relationship that is achieved between technology, processes and people.

This technology has a broad application range because it integrates the different operational levels while minimizing financial risks. The use of this technology can be leveraged to most of the current artificial lift systems and it is compatible with many of the drivers/interfaces available in the market.

This helps to reinforce in Argentina the incorporation of technology as a management tool for the exploitation of oil fields. It can boost corporate social responsibility, by having a significant impact on profits with the available resources and integrating the organization towards operational excellence.
An Integrated Pathway to Enhance Human Talent
Authors: Hasselmeyer J. , Lobo L. Vielma
Published: April 2012

Managing Human Resources Development with an integrated and systematic approach is the key to individual and business success as it enables managers to identify and use the talent strengths for the benefit of the organization while motivating individuals towards their personal and professional growth.

Based on the though above mentioned, we developed a Continuous Human Development Model (CHDM)*, anchored to the Strategic Business Plan, with emphasis in the Human Resource Strategic Direction. The Model is composed of five interrelated processes. The first one is related to the Recruiting and Selection of Talents and the Induction - Training required before they are appointed to the organization's positions. The three following represent the Core of the CHDM: Education and Training based on a previous Competencies level measurement, Career Development and Reward linked to Performance Appraisal. The Training based on Competencies process favors the identification of gaps between the employee's knowledge and the level they require to generate superior deliveries. The Career Development process includes: The Individuals Development Plan which is designed based on career paths and employee potentiality, and the Succession Plan for each key position, to assure the availability of candidates. The Reward, linked to Performance Appraisal, aligns individual to the Business Strategy, Mission and Vision. Last but not least, is the Retirement process which is conceived to prepare and enable employees to cope satisfactorily with a new environment and a different lifestyle.

The Model described was put into place by the Human Resource Department, of the Exploration and Production Division of two National Oil Companies located in South America and Central America, generating benefits to the business such as availability of: technical and managerial talents due to early talent identification, career paths and chart replacements for key positions and relay generation. It also brought some additional and intangible benefits like personal alignment to the organization strategic guidelines and reinforcement of a goal oriented culture, among others.
Water Coning in Naturally Fractured Carbonate Heavy Oil Reservoir – A Simulation Study
Authors: Pérez-Martinez E. , Rodriguez-de la Garza F. , Samaniego-Verduzco F.
Published: April 2012

During production in a naturally fractured reservoir with natural water influx, under certain flow conditions an imbalance can be generated between gravity and viscous forces within the fracture system. This phenomenon is characterized by the gradual growth of a cone of water in the vertical and radial directions. When the radial growth of the cone base at the oil-water contact reaches the drainage radius, the cone of water reaches its maximum height. After this, the oil-water interface advances without suffering deformation in the pseudo stationary regime. However, when this interface is a short distance from the bottom of the completion interval, the movement of the oil-water interface accelerates and water flows into the well. This phenomenon may shorten the well's life due to the complexity of oil-water separation offshore and resulting increases in operating costs.

In many of the Cretaceous formations of the offshore Mexico Bay of Campeche, oil recovery is limited at the top by the presence of a gas-oil contact and at the bottom by an oil-water contact. To recover the remaining hydrocarbon reservoirs it is necessary to: (1) define the optimal operating range which should be established for each well to delay water and gas breakthrough and (2) to schedule the necessary infrastructure to handle high production rates of water and gas as the field matures.

The objectives of this work are to:

Model in detail the water coning in the porous fracture system using a fine radial grid, with one meter thick layers concentric around the well, and 2 inches thick layers in the annulus, with and without cement.

Obtain an equation to determine the maximum height of water coning, the time it takes to form the cone, and the well shut-in time necessary to undo or "heal" the water cone.
Talking to the Reservoir through PDGs: A Brazilian Deepwater Oilfield Case
Authors: Feitosa Gilvan Soares , Lucas Marcos Aurélio
Published: April 2012

Production and injection bottomhole well pressures, when continuously monitored by permanent downhole gauges (PDGs), are sources of real-time valuable information on the reservoir behavior. Indeed, well flow rates and associated pressures constitute the language we talk to the reservoir, which must be understood by reservoir engineers. Controlled by reservoir-well parameters - such as rock and fluid properties, geometry and well constraints -, pressures and flow rates, when properly analyzed, are essential to guide the actions to optimize reservoir exploitation.

This paper presents the analyses carried on flow rates and associated pressure measurements recorded by PDGs placed at a pair of wells, an oil producer and a gas injector well, designed to drain a light oil deepwater reservoir, off coast of Brazil, and applications of its results to simulation models and reservoir management. The pressures so monitored have enabled to obtain valuable reservoir parameters and their evolution, through analysis of drawdowns, buildups and interference between wells. Main parameters and information include: volume of oil in-place, reservoir average pressure, productivity and injectivity variation associated with the evolution of damage and fluid saturation, and degree of communication between wells. In particular, these data have improved the history matching process, thus contributing to shape up more reliable simulation models that have been used for production forecasting.

Pressure recordings span over one and half years and include a huge amount of data, over 11 million points, one of the challenges that had to be handled. It is shown that the deconvolution applied to the measured pressure-rate data stretches the period suitable for analysis, leading to deeper reservoir investigation, detecting boundaries that otherwise would be unnoticed, what makes PDGs pressure recordings even more valuable. Due to high transmissibility and size of the reservoir, the pressure responses to disturbances caused by heterogeneities and boundaries, as well as by variation in well flow rate, are readily sensed and registered by the PDGs in short period of time, at both the producer and the injector well, what yields recording real world textbook-like reservoir behaviors, which may not be often found in the literature.