bluuebunny/crossref_metadata_2025 huggingface dataset:
Sweet Spot Geological Techniques for Detecting Oil Field Exploration Locations
Authors: Carrasco Javier , Trillo Enrique M.
Published: November 2015

A significant challenge for the hydrocarbon industry at the beginning of the current century was related to geologically high-risk oil and gas reservoirs. This led a new generation of geoscientists to focus on three important areas: mature fields, deep water, and unconventional reservoirs. Fortunately, several technological drilling and software innovations have helped further the understanding of global petroleum systems. This paper discusses a case history in which geological integration was performed by a diverse group of geoscientists of varying disciplines, whereby the introduction of integrated geological techniques using computer systems allowed a better conceptualization of reservoir behavior, helping to reduce analysis time. The integrated method uses TIER quantification, which allows enhanced visualization for specialists to identify potential hydrocarbon zones and volumes in the reservoir. This involves generating a two-dimensional (2D) sweet-spot map that is overlaid on petrophysical maps to show the distribution of principal reservoir properties (e.g., effective porosity, hydrocarbon content, pore volume, permeability, sand volume, etc.). Petrophysical evaluation curves are used to calculate a three-dimensional (3D) sweet-spot log using a computer program, which facilitates modeling of the heterogeneity and depth range of the reservoir. It is possible to populate the 3D sweet-spot distribution into a geocellular model. The integration of the sweet-spot distribution, seismic attributes, historical oil production, and petroleum system studies allows for better determination of possible hydrocarbon reservoirs. This helps reduce uncertainty related to potential geological exploration opportunities. The original oil-in-place (OOIP) can be calculated using 3D geocells conforming to arrangements of simulation layers. The static geocellular model then undergoes scaling, which is transferred to a numerical simulator.

This methodology has been applied in the tight-oil sand reservoir of the Chicontepec channel in Mexico, which is composed of a high stratigraphic element having a concentrated trend of productive Upper Paleocene sands. The structural fault model was not severely affected in the area of interest; therefore, it can be used as a reliable geological model to simplify the integration of sweet-spot distribution for prospective sand intervals.
Methodology of Feasibility Study on Pilot Test for Dump Flood Completion System
Authors: Villarroel A. J. , Nieto Miño M. D. , Estrella K. I. , Perez J. A.
Published: November 2015

The "dump flood completion" (DFC) is a mechanism conceived to inject water from a reservoir with an active aquifer into a depleted reservoir using a drilled well with marginal production or closed due to low pressure. This innovative mechanism allows for saving the costs of drilling an injector well as well as expenses associated to building additional surface facilities, and water treatment procedures.

This study includes using dynamic models to evaluate scenarios linked to different DFC schemes, with the goal of increasing the net present value (NPV), while maintaining/increasing pressure in the reservoir.

A multidisciplinary team developed a detailed static model to better represent within the dynamic model, the sedimentary bodies dimensions, fluids flows, and the corresponding pressure changes.

The static model build used an exhaustive structural framework comprehensively coupled to the reservoir sedimentology model: facies and rock types, bodies' preferential directions, and bodies' dimensions. Before populating properties, sensitivitiess were performed to obtain an optimum grid and better represent facies lateral changes. The facies distribution model was created from the discrete curve of facies proportionality and using bodies dimensions defined in the sedimentology model. The netgross model was based on Vshale/porosity cutoffs. The porosity and NetGross characterizations were generated based on the facies modeling, and using the Sequential Gaussian Simulation (SGS) technique. The P50 of the stochastic simulations was used to establish the OOIP value.

The resulting static model was input into a black oil simulator to history match production and pressure, and obtaining a base case for prediction purposes. Subsequently, the sensitiy of the reservoir performance on most significant paramters, i.e. water injection rate, bottom-hole pressure, and number and location of injector wells, was analysed. The procedure was assisted by an optimization simulation tool to obtain optimum values of net present value (NPV). The final result was considered the most optimium injection pattern applicable to the current reservoir conditions.

Methodology and modeling techniques applied in this study can easily be extended to reservoirs in the basin with similar features.
Comments on Babu and Odeh's Model for Productivity Prediction of Partially Penetrated Horizontal Wells
Authors: Grassi E. , Zhu D. , Hasan R.
Published: November 2015

In this work, Babu and Odeh's model for estimating flow rate from partially penetrating systems is studied. A VBA code is written in order to simulate the model and its results are compared against simulations using Eclipse Software. Sensitivity to different parameters is analyzed.

The results obtained are compared against Eclipse runs, it is observed that the model is reasonably accurate.

It is concluded that the model is accurate within its simplistic assumptions, but it is in these same assumptions that it might yield very different results than reality itself.
Reservoir Compartmentalization in a Naturally Fractured Reservoir through Production-Pressure Performance and Compositional data
Authors: Paredes J. E. , Arana M. C. , Larez C. J.
Published: November 2015

Naturally fractured reservoirs (NFR) are generally subdivided into segments that behave as separate flow units due to the flow barriers (areal and vertical) generated by multiple fractures networks present in the reservoir.

This implies a challenge to predict the dynamic behavior of a reservoir when the degree of compartmentalization and blocks that form the reservoir is unknown. Generally, reservoir compartments are identified by geological events and not based on the dynamics.

This work proposes a methodology that attempts to describe and identify the compartments of a NFR through a dynamic analysis including:

– Production behavior (water, water-salinity, oil and GOR) – THP and BHP behavior (HPHT real time data) – Orientation and intensity of fractures – Analysis of the compositional variation of the fluid (vertical and areal) – Multi-tank model analysis (Material Balance) to identify faults transmissibility using in the simulation model

The proposed methodology was successfully applied to a NFR in the South of Mexico that presents problems in the History Matching process in its numerical simulation model.
ECD and Downhole Pressure Monitoring While Drilling at Ecuador Operations
Authors: Andagoya Carrillo K. I , Avellán F. J. , Camacho G.
Published: November 2015

For the period different drilling campaigns took place at the Tapi and Auca Fields, Ecuador. A downhole monitoring pressure tool helped identify some important pressure behaviors and scenarios.

The ECD monitoring led to better wellbore cleaning, drop of mud weight detection not detected on surface and improvement of drilling operation times by deciding whether it was necessary to make short trips or not, based on the acquired data. All the gathered data allowed the creation of a database that will become the baseline to improve future drilling projects in those fields.

The tool uses a quartz crystal type transducer that grants high resolution and accurate readings in real time and memory of annular pressures and bore pressures. Additionally, ECD (Equivalent Circulating Density) and ESD (Equivalent Static Density) measurements are calculated and this last one also defines an inherent value of the EMW (Equivalent Mud Weight). The tracing of these values show the performance of the drilling fluid and an ECD working frame could be defined to ensure effective cleaning of the well.

In order to understand ECD, external factors affecting its behavior need to be denoted such as flow patterns, ROP or drilling fluid properties. Additionally, the applications of pressure records when performing FIT, CIT or LOT are explained.

Different scenarios of how the data was analyzed, interpreted and the decisions taken during the operations are shown in this paper.
Integration of Formation Evaluation Domains for an Optimized Perforating Design
Authors: Morales O. , Bravo J. L. , Lomas J. , Madruñero C. , Vallejo R. , Rabanal J. C. , Pastrana W.
Published: November 2015

Petroamazonas EP is the national oil company in Ecuador. It holds most of the oil concessions Onshore and Offshore in the country. The oil and gas production targets require implementing advanced analysis that provides effective results on production.

In order to analyze and predict the well Productivity, it is necessary to perform an appropriate perforating analysis; this can be achieved integrating Petrophysics, Geomechanics, Reservoir and Production Domains. For an advanced Perforating design a clear understanding of rock characteristic, depth of damaged zone and reservoir behavior is used in the Perforating simulation. This enhances the right selection of charges and ensures they will overpass the altered zone. Step by step procedure is described:

Petrophysical evaluation and rock strength of the formation of interest. Quantification of alteration depth. Display the penetration profile. All this previous steps are used in order to obtain a detailed Flow Profile. To identify and select with the Flow Profile the better zones to produce. A sensitivity analysis is performed to select the best scenario for a technical and economic decision.

This methodology was implemented in two of the key Petroamazonas EP assets, which are Amistad Offshore Gas Field, and Apaika Onshore Oilfiled. This helped to optimize and predict the productivity of the wells.

The following conclusions were obtained once the wells were on production:

Selection of the better intervals to produce Low Uncertainty of well productivity prediction Confirmed effective communication between borehole and reservoir Skin reduction due to a better perforating selection and design Optimized completion design Making proper decisions when analyzing project cost versus production.
New Techniques Aimed at Facilitating Application of Directional Casing Drilling in Ecuador
Authors: Ramírez H. , Breton M. , Lougon A. P. , Rodriguez R. , Barreto M. , Chancay J.
Published: November 2015

Directional Casing while Drilling (DCwD) in Ecuador has been technically evaluated as a well construction technique to reduce or mitigate operational problems associate with: 1) constructing wells that could not be drilled efficiently using conventional techniques in partial and total lost circulation scenarios, through swelling shale or with hole instability issues, tight hole or stuck-pipe applications; 2) or to reduce total operational costs by eliminating casing runs, short/wiper trips and increase ROP.

At last count there have been over 200 worldwide directional casing drilling runs both onshore and offshore. These runs have been successfully executed in some of the most challenging drilling theaters making DCwD a viable and cost reducing alternative which helps operators solve the previously mentioned problems. To support the introduction of DCwD in Ecuador, rigorous engineering analysis has been performed which involves both the economic and technical aspects to help determine what kind of casing drilling system and BHA configuration is most suitable to ensure a successful run.

Modeling sofwares have been used to evaluate drilling dynamics and hydraulic requirements enabling engineers to select a drillstring that is capable of performing the specified job and obtain the required performance improvement with DCwD. The digital analysis helps to accurately predict if the application is suitable and determine which parameters could be applied to efficiently and safely execute the DCwD application.

There are some factors or parameters that can be taken as benchmarks when analyzing both static and dynamic simulation results. Torque determines if the rig has the capacity to drive the system. Fatigue and buckling analysis provide inferences into casing pipe selection and connection type. Realistic friction factors used during the simulations will avoid obtaining erroneous results which could lead to serious drawbacks. Scenarios like magnetic interference, presence of conglomerates or boulders could limit the tools' used for a specific application. The recommended BHAs will be supported by the specific regional analysis in addition to successes in other similar worldwide applications.

Once the engineering analysis has been completed, economics are then considered. The directional casing drilling service cost versus the amount of saving obtained by applying this technology has to be thoroughly evaluated. Savings will be couched as either time and/or money. Both have to be evaluated in the short and long term to determine which applications would benefit from DCwD and which environments should be avoided. The authors will explain how this analysis is performed to obtain an adequate feasibility study to meet the client's objectives. They will also discuss the key performance objectives that must be considered during each step of the analysis.
A Real Case Study: Field Development Plan Evaluations for Oso Field
Authors: Sierra F. , Monge A. , Leon S. , Vasquez F. , Garcia J. , Llerena G. , Borjas J.
Published: November 2015

The asset Oso-Yuralpa has 7 fields and 323 completions, located in the Blocks 7 & 21 of Ecuador. The oil cumulative production reaches 168.5 MMSTB. The active wells produce using electric submergible pump, hydraulic jet pumps and natural flow, mainly from 3 production zones. In surface, the production is processed in two flow stations, with high capacity processing.

This project was focused on Oso Field, located in the asset north area. Due the aggressive drilling campaign and the consequent increase in the daily production activities, has created the need to evaluate the impact on the surface facilities.

The scope of this study is evaluating different field development plans, integrating reservoir to surface facilities, that includes reservoir description, well models configuration, fluids gathering network, process facilities and economic indicators, with the objective of visualize and optimize field production, better decision making and operational planning considering long term life cycle.

Working in four scenarios was evaluated, as follow: Base Case: Operations at current situation.Drilling New Wells: Execution of drilling campaign to create 35 new wells using four rigs.Drilling Campaign with Delays: Considering delays in drilling schedule.Drilling Campaign with one rig less: This scenario considers one rig less.

The results in terms of cumulative production and recovery factor, estimates a maximum recovery factor of 4.2%, with and an additional cumulative production of 87.52 MMSTB with an increase of 1023 MMUSD in the Net Present Value (NPV). The Operating costs increase in 30% due investments in drilling campaign and fluid processing in surface.

As conclusion, the fourth scenario (Drilling Campaign with one rig less) gives the highest profitability index with the lower operational costs, which represent the recommended development plan.

The implementation of and integrated asset study, permit evaluate the project profitability in different scenarios, identify bottlenecks in surface network and measure the investment and costs uncertainty.

The present study allows the knowledge sharing between disciplines, making possible evaluate and visualize the asset development with sustainable technical and financial indicators.

The continuous evaluation of integrated models, serve as base for further production optimization and risk analysis studies, and could be applied in other assets.
Integrated Characterization Workflow Enables Ecuador NOC to Increase Oil Production from Very Thin Sand Reservoirs
Authors: Izurieta A. J. , Pastrana W. , Pazos J. , Davila E. , Chavez J. C. , Vallejo R. , Bastidas D. V. , Luzuriaga A. , Hernandez A. Diaz
Published: November 2015

The objective of this paper is to describe a comprehensive approach integrating static and dynamic well characterization to optimize well completion and subsequent improving oil production in thin sand reservoirs.

The following procedure was used to estimate and optimize the production potential of 3 feet sand reservoir located in Limoncocha Field: Accurate well logging program to identify thin sands. (Vertical Resolution, Static Data)Open Hole Mini DST program to estimate permeability, skin effect, and reservoir pressure and productivity index. (Dynamic Data)Anchored guns with 800 psi of static underbalance to avoid control fluid invasion.Well completion done with drilling rig; No well test is required using this methodology.PVT sample taken in cased hole for further characterization and continuous improvement.

Traditional workflows created by operators companies in the Ecuadorian Oriente Basin usually work very well in formations over 20 ft. thick. When such workflows are applied to thin reservoirs, frequently leads to bypassed zones with under estimated production potential. In order to offset this typical scenario, the G&G team working at Limoncocha field developed an integrated workflow to properly perform dynamic and static characterization of this type of zones to determine well productivity and the best completion method at an early stage while the well is still open hole. For this particular case study by a proper analysis the G&G team was able to characterize and predict oil production from 3 feet thin sand located at 11200 ft depth.

Mini DST technique played a vital role in the process, becoming the optimum link between static and dynamic data that allowed the proper workflow integration. The application of an early integrated well characterization allowed to set an optimum completion system design including state of the art perforating and optimized ESP design with no prior well test resulting in an improving oil rate of 850 stb/day from 3 feet thick sand overcoming the idea that it is a low productive or no pay zone regarding its current cumulative oil production of 126 MMSTB. This methodology truly predicted the production potential opening a new scenario where deep thin sands are now considered economical

Considering that the "easy" oil almost gone in the Oriente Basin, this paper describes an innovative workflow that allows proper planning to produce successfully thin reservoirs which in the past were considered low or non-productive.
Rock Typing Mapping Methodology Based on Indexed and Probabilistic Self-Organized Map in Shushufindi Field
Authors: Leon M. A. , Lafournere J. P. , Bourge J. P. , Bolanos M. J. , Bringer F. , Navarrete J. , Hurtado J. , Gozalbo E. , Suter A. , Henson R. , Rodriguez J. C. , Castillo F. , Ochoa J.
Published: November 2015

The Shushufindi field is located in the Oriente basin of Ecuador. The field was discovered in 1972 and widely developed with about 247 wells covering an area of approximately 400 km2. The implementation of lithofacies characterization in 98% of the existing wells has given a reliable description in about 92% of the wells in the current geomodel, which demonstrates, the validity of the deterministic method.

A robust petrophysical rock type (PRT) classification can significantly improve the chances of success for all wells, focusing on layered reservoir rocks recognized as the major energy resource in recent years. The vertical and lateral classification of rock heterogeneity in the form of rock types is critical to understand the flow dynamics of the reservoirs. Well logs are the best option for formation evaluation as they provide high vertical resolution measurements. However, rock type's classification using only well logs interpretation techniques, has its limits.

In this paper, we introduce a rock type neural network technique based on Indexed and Probabilistic Self-Organized Mapping (IPSOM) which was designed for the geological interpretation of well log data, facies prediction and optimal derivation of petrophysical parameters. The rock typing was based on cored wells in a 3-step approach. Preliminary rock type identification was based on sedimentology description and routine core analysis. In parallel, it was refined with high pressure mercury injection data to describe accurately the porous media. The porosity and permeability ranges were established to elaborate a sand facies classification represented by Petrophysical Rock Type through Winland method. The neural network was first trained on cored reservoirs, and then propagated to uncored wells using the classification model relationship with electrical logs. Finally using the IPSOM classification model, a permeability-porosity relationship for each rock type was obtained, providing input to the dynamic model to predict and validate permeability.

This paper present a reservoir characterization enhancement technique using neural network, which has proven its utility in refining the dynamic model of the Shushufindi field and directly contributing to the operator by improving production from layered reservoirs.
Pipeline Integrity Management in High Environmental Consequence Areas
Authors: F. Eguiguren G.
Published: November 2015

In 2009 Repsol Ecuador developed several root cause analysis in order to define the strategy for threats control as corrosion or third party damage. In conclusion it was defined the need to develop a pipeline integrity management plan based on international standards which ensure threats control and reduces leaks rate.

In 2010, a pipeline integrity management system based on the standard API 1160 "Managing System Integrity for Hazardous Liquid Pipelines" has implemented in order to ensure reliability and availability of the pipelines.

It starts with an external audit in compliance with criteria of standards API 1160 and ASME B31.8S as well as the requirements of CFR 195. The audit showed that Repsol Ecuador was meeting 37% of these requirements and provided an opportunity to identify where to should improve.

The plan developed by Repsol Ecuador for pipeline integrity management consists of the following parts: Determination of High Consequence Areas "HCA" in case of leakage or total failureStructured methodology for risk analysisDetermination of baseline of mechanical integrityDevelopment of Risk Mitigation and Control plansRe-evaluation of riskAudit Plan and KPI

As a result of the implementation of pipeline integrity management plan it can be mentioned the following:

To identify high consequence areas it was necessary to develop a new definition based on the API 1160 criteria but modifying them to accomplish the Ecuadorian reality and precisely the zones of influence of Blocks 16 and 67. It was determined that all Repsol Ecuador operation is been developed into a HCA.

A methodology for risk analysis based on the criteria of Pipeline Risk Management Manual by Kent Mulbahuer and following the criteria of the Repsol's corporate standard for risk analysis. The result of this analysis was the clear evidence that the greatest threats to the pipelines are internal & external corrosion and third party damage.

Based on the risk analysis, the baseline was determined by In Line Inspection and methodologies as ECDA. From the results mitigation plans were executed.

Currently and by using a software tool called Pipeline Integrity Data Tool, Repsol Ecuador integrates all information from daily operations, maintenance, inspection, etc., and defines the distribution of resources to prevent spills. As main results, the leakage rate has decreased from 23 leaks/ 500Km – year in 2009 to 4 leaks/ 500Km-year in 2014 in piggable pipelines.
A Deepwater Gas Field Development Strategy for T&T
Authors: Nickie Ayasha
Published: November 2015

The phrase "a cleaner and environmentally attractive fuel," describes why the gaseous hydrocarbon, natural gas, is a favored fuel choice compared with other hydrocarbon fuels and coal. Its emergence as a preferred fuel has grown throughout the years and as such worldwide consumption and production have escalated.

Trinidad and Tobago is the top natural gas producer in the Caribbean with an average 2014 daily production of 4,069 MMscfd. With a vibrant upstream, midstream and downstream sector, Trinidad and Tobago makes maximum use of the natural gas value chain. Further maximization through growth in Trinidad and Tobago's downstream sector requires an adequate supply of natural gas in addition to the shallow water gas fields offshore Trinidad and Tobago which are currently the main supply source. Deep water gas fields have the potential to increase supply but unlike oil, the ease and economics of development are challenging. As a thriving gas sector, a myriad of infrastructure already exists which may aid with any further development.

An understanding of the magnitude of investment, its return to both operator and government and the well head price to economically produce natural gas from deep water fields is critical especially for potential domestic and Caribbean markets. For Trinidad and Tobago, an economic option to develop potential gas resources in deep water fields would bolster further downstream investment and by extension the economy. Regionally, potential markets can also be served via this supply. This paper therefore focuses on a deep water gas development strategy which utilizes Trinidad and Tobago's existing infrastructure. It presents a technical and economic evaluation of a deep water gas field based on three (3) recoverable resource sizes, one price structure and a production range of 500 mmscfd to 750 mmscfd. The development strategy along with associated capital and operational expenditure, Net Present Value (NPV) discounted at 6%, 8% and 10% nominal to January 2015, Government and Operator share percentages and internal rate of return (IRR) are highlighted.

The paper concludes that initial investment for a resource size of 3tcf to 5tcf would be between five (5)-eight (8) billion USD. Economic returns to both Operator and Government for these deep water, dry gas developments requires a well head price of greater than USD 3.50 per mscf. Government share % ranges from 19 % to 35% and for the operator, an NPV of USD 1.2 Bn to USD 2.3 Bn can be achieved.
Optimizing Well Evaluation: Real Time Monitoring Using Fiber Optic Conveyed in Coiled Tubing and N2 Lifting
Authors: Villanueva G. , Burgos J. , Humbert O. , Betancourt A. , Lopez M. , Sandoval L. M. , Arevalo J. C. , Hurtado J. , Meza D. , Torres C. , Gozalbo E. , Vela I. , Egas A. , Leon R. , Loyola R.
Published: November 2015

Well evaluation is the primary method used in the oilfield to determine the true well's production potential and reservoir characteristics. During a well evaluation, downhole parameters are commonly registered using downhole memory gauges, which can only be retrieved and read after the evaluation have finished. The problem with this conventional method is the uncertainty or ambiguity results and the inaccurate data of the downhole parameters; which often lead to inefficient tests times and difficulties for well test interpretation.The use of Fiber Optic for Real-time downhole measurements conveyed on Coiled Tubing (CT) and Nitrogen (N2) Lifting provide a unique live insight that allow us to monitor the well response while production or evaluation is performed, eliminating the uncertainties that surrounds traditional methods.

Nitrogen lifting with Coiled Tubing was introduced as an alternative evaluation method for the common Hydraulic Jet Pumping that proved advantages accelerating well response and increasing the accurate of the reservoir data for well evaluation and artificial lift design nevertheless this still faces the delayed on the pressure data and transient interpretation. Implementing the Real Time downhole measures (P, T) is possible to eliminate uncertainties of reservoir parameters that surround well evaluations, adjust job parameters on-site, optimize job resources and time and finally anticipate artificial lifting design.

This paper will present the results of the implementation of this new method in the area for well evaluation allowing real-time measurements of down hole pressure/temperature. Combining the fluid lifting with N2 through the CT, reservoir response is continuously monitored; thereby, allowing in advance an adequate design of the lifting system reducing nonproductive time. Real-time measurements and accurately data of the reservoir allow defining if a further stimulation treatment is needed. Actual treatment program can be continuously monitored or modified, to achieve optimal results.

The first trial using the system demonstrated that the application can be used with a high degree of accuracy and control for the parameters and treatment designs that are not achievable using conventional techniques as the Hydraulic Jet pumping, gauges conveyed in slick line, joined tubing and/or using surface data to predict downhole behavior.
Learning by Impact Driving Training: A Case Study from Ecuador
Authors: Pazmiño Aldaz K. , Kohatsu J.
Published: November 2015

Road traffic incidents are ranked by the World Health Organization (WHO) among the top 10 causes of fatalities worldwide. According to reports from the International Association of Oil & Gas Producers (IOGP), driving-related incidents continue to be the single largest cause of fatalities in the oil and gas industry.

With an increase in driving-related activities in its operations in Ecuador, an oilfield services company reinforced its approach for driving training in that country by developing a "Learning by Impact" component. Based on the principle that people learn by repetition and impact, the approach represents a change of focus compared to the previous training, which was mostly theoretical. The objective of the "Learning by Impact" initiative was to encourage safe driving behavior combined with good driving skills training in order to further improve driving safety performance.

The training program implements real-life situations such as rollover, frontal crash, seatbelt and motorcycle convincer simulator devices, reaction stick (using a cell phone), vehicle pre-inspection and role-plays. The training is consistent with IOGP 365 guidelines for driver safety improvement. Equipment was custom designed and built to provide simulators of vehicle accident situations. These simulators are portable, enabling the training program to be easily moved to multiple locations in the country wherever driver training is required.

This paper describes how the program was developed and implemented, and how the approach, with its focus on practical experience of simulated real-life situations, is considered to have been successful in increasing drivers' awareness of their behavior and its potential impact of driving incidents.
Successful Implementation of Hydraulic Fracturing Techniques in High Permeability Heavy Oil Wells in the Llanos Basin-Colombia
Authors: Italo Bahamon J. , García C. , Manuel Ulloa J. , Leal J. , Garay R. , Medina C. , Nieto J.
Published: November 2015

Hydraulic fracturing is the most common stimulation technique to make hydrocarbon production feasible and optimal worldwide. However, it has been preferentially focused on low permeability formations, and when applied to high permeability, it has been focused on sand control.

This article outlines the process and results of the hydraulic fracturing campaign for productivity purposes (not for sand control) in the basin of the eastern plains of Colombia given the petrophysical characteristics of the cretaceous formations, where thinking "out of the box" and separating from the existing premises, resulted in successful implementation of this technique in high permeability wells (~ 1D), high water cuts (up to 80% BSW) and heavy oil reservoirs (9–12 API).

The technical process consisted on several steps leading to the success of the campaign, which included: Formation damage study that identified candidate wells and damage mechanisms affecting them.Refining of the petrophysical model from pressure testing to establish incremental production.Adjustment of fracture models using varying anisotropy from special sonic log runs.Using state of the art technologies such as mobility enhancers and Flow back proppant additives as active ingredients of the fracturing fluid.

This article presents the outcomes of more than 40 wells intervened to date with an average volumetric increment of ~ 250 BOPD per well, consistent reductions of BSW up to 60% and optimized operations which let the operator consider the hydraulic fracturing as a production optimization option for the field under analysis.
Integrated Geological, Petrophysical, and Reservoir Properties of the Upper and Middle T Sandstones, Tarapoa Block, Oriente Basin, Ecuador
Authors: Espinosa J. W. , Good D. R. , Verdin C. Torres , Steel R. , Olariu C.
Published: November 2015

The Upper T Sandstone of the Tarapoa Block in the Oriente Basin of Ecuador demonstrates low resistivity despite often containing light gravity oil, the presence of which has been confirmed through tests and production. This situation merits an in-depth analysis to better understand the reasons for, and the impact of, the low resistivity as a key factor in conventional petrophysical analysis; and in so doing, improve the precision of determining the hydrocarbon content and productive potential of the Upper T reservoir in the Tarapoa area.

At first, it was considered that the principle cause of the low resistivity effect in the Upper T interval was the presence of glauconite which is deposited in a shallow marine environment, however, upon more thorough investigation, it was determined that, despite the real impact of glauconite, there are a number of other variables which contribute to this anomaly, such as thin bed sand/shale alternations, grain size variation in the sandstones, and the vertical resolution of the conventional wireline tools typically used.

A thorough analysis and understanding of the Upper T reservoir rock is justified in order to determine its real hydrocarbon potential, and to help in the calibration of the reservoir potential when proposing well locations. In addition, a better understanding of the variables impacting the reservoir quality and flow characteristics is of great importance when proposing test intervals and in the design of testing and production parameters.
A Successful Peripheral Water Injection in a Weak-Edge Aquifer Oilfield, Oriente Basin, Ecuador
Authors: Feng Yuliang , Ji Bingyu , Sun Hongjun , Wan Xuepeng , Solis Ivan , Tan Xuequn , Li Linlin , Zhang Shiyang
Published: November 2015

HN oilfield1, Oriente Basin, Ecuador, is located in the rain forest, well deployment is restricted by ground environment, and surface facility installation is under very strict regulations2. In this paper, a successful peripheral waterflooding3 application in the HN oilfield, was illustrated. Geological study, waterflooding design, project deployment and waterflooding optimization were thoroughly discussed in detail.

M1 of Mesozoic Cretaceous Napo Formation is a litho-structural composite reservoir, mid-high permeability, with thin sand layers4. The production was initialized in 1995 with natural depletion drive, and a 6.4% recovery of OOIP was achieved. In order to enlarge the waterflooding sweep volume, three injection wells were designed. Well location is optimized on the basis of fine interpretation of low relief structure and prediction of sand with average thickness of 15 ft by MPS method5. A proper injection-production ratio(IPR) was determined by using reservoir simulation to restore the reservoir energy but avoiding to reach high water-cut values on producer wells. Volume and properties of the aquifer was estimated by static-dynamic analysis. A "balanced injection" method was applied and real-time waterflooding adjustment was carried out to enhance waterflooding performances.

As liquid production and pressure declined sharply after 8 years' primary drive, in 2003, one injection well was drilled to performance peripheral water injection. The volume and properties of the aquifer were re-estimated according to the production history data and geological analysis. Oil production started to increase and reservoir pressure was restored. The BOPD in 2003 was 950bbl/d, and peaked at 2,300bbl/d in 2007. Later, another two injection wells were drilled to enlarge the sweep volume. But one of them was changed to inject in another zone. Injection volume, pressure, and injection mode were studied and optimized, the oil production peaked at 5,400bbl/d in 2010 as the results of injection optimization. The efforts of real-time waterflooding adjustment extended the high oil production period. By July 2015, RF reached 32.7% with 83.4% water-cut and an ultimate recovery was forecasted to be 45%. Due to effective reservoir management, maximized economic benefit was achieved on the basic economic evaluation. Suggestions on future adjustments were given for waterflooding operations in this field and similar oilfields.

The successful application of waterflooding demonstrated the potential of peripheral water injection in complex reservoirs and the importance of water flooding design. Due to integrated geological study, reservoir performance analysis, and reservoir management, waterflooding operations achieved its best performance with maximum economic benefits.
Interpretation of Micro Resistivity Image Logs and Core Tomographic Images in a Natural Fracture Reservoir Evaluation, Upper Magdalena Valley, Colombia
Authors: Mantilla M. , Davila D.
Published: November 2015

In the Upper Magdalena Valley, 70 kilometers south of Neiva La Hocha Field is located, on the low side of the San Jacinto Fault, structurally defined by a "Z" type anticline with dips between 45 and 90 degrees. Its geological information is obtained from wells and is standard requirement to run image logs to characterize the structure dip and fracture behavior. Uncertainty related to fractures trends and structural dip, are principal reasons of this analysis.

Micro resistivity image interpretation, core data, core tomography images, field closeness to a regional fault (between 0 and 600 meters) and reservoir production information have allowed identifying it as naturally fractured. Recently, a core was acquired, analyzed with high resolution tomography and integrated with micro resistivity image logs, to characterize and integrate the rock with well logs, then to extrapolate the results to other wells in the field.

The integration allowed confirming planes originally associated with structural dips, identifying fractures on the core that the image log resolution did not permit, interpreting fractures using core tomography radial images, similarly as in image logs. Several features were interpreted and based on fracture dip and strike direction three fracture families were defined, with a predominant strike direction of NW-SE.

This combined analysis helped to establish a fracture trend pattern or criteria that represents great information for future fracture and structural models in La Hocha field. Additionally, this pattern will be extrapolated to other wells with micro resistive image log in the field, adjusting and improving those results, obtaining a better model.
A Simple Yet Effective Approach to Estimate Time and Costs for the Drilling Project in the Tapir Field
Authors: Rodriguez Rafael U.
Published: November 2015

Budged estimation for a given drilling project is part of the dutties assigned to drilling engineers. The simplest way to make those estimations is using average costs based on previous wells, which works well to a certain degree.

Average time and costs sometimes include troubles experienced in wells that could increase the estimation.

This paper presents a simple procedure to make more realistic estimations based on the actual well design of the wells to be drilled and the information compiled from wells already drilled. The Tapir field in Andespetroleum was used to prove the effectiveness of this approach.

Time estimation for drilling operations is made from the information collected in a database, which considered the previous wells drilled in the Tapir field. Wells were classified by their directional profiles, their displacement, their direction and maximum inclination.

The collected information also included a record of average ROPs for each section of the wells, time spent for each trip, and also the time spent in other operations such as open hole logging, casing running, cementing, wellhead / BOP installation, etc.

Once the conceptual design of the new well is ready, wells with similar profile are searched into the database trying to find one well with the closest possible profile respect to the well being planned. This well is called the pattern well. Then, a simple spreadsheet is used to quickly estimate the time for drilling operations using the pattern well as reference.

Oportunities for time optimization are derived from the lessons learnt from each well.

On the other hand, the cost estimation uses a very simple spreadsheet that collects all the associated services involved in drilling a well. It is important to point out the advantage of having services that are paid using a lump sum (drilling fluids, directional services, cementing, etc) which provides a very simple way to estimate costs with a good degree of accuracy. The lump sum contract model for almost each service was adopted after several years of experience in the area that resulted in a good knowledge of the risks and operations associated.

An example of how to use this simple approach is showed and a comparison for planned versus real time and costs are also presented.
Geomechanics Coupled to Fluid Flow in Heavy Oil Reservoirs: Comparison and Innovation in the Modelling
Authors: Alvarez L. L. , Alzate-Espinosa G. A. , Naranjo A.
Published: November 2015

Nowadays, a large percentage of oil daily production in some Latin American countries comes from heavy oil reservoirs. The oilfield development and reservoir exploitation strategy for this kind of reservoirs must take into account the impact of geomechanical issues on modelling any reservoir production scenario, either for a single well or sector model simulator. The modelling or simulation tools used to represent the performance and behavior of heavy oil reservoirs present some limitations such as they are not fully coupled and they only use a nonlinear elastic constitutive model to represent the mechanical behavior of the reservoir. Both examples show major limitations to figure out a closer analysis to the true behavior of heavy oil reservoirs. The geological formations related with mentioned reservoirs usually present a mechanical behavior similar to materials with very low capacity to support changes in the stress-state and to present permanent and unrecoverable deformations after loading and unloading processes. Therefore, to analyze the behavior of heavy oil reservoir is mandatory to use modelling tools that incorporate a coupled analysis between fluid-flow process and strain-stress using an elasto-plastic constitutive model.

The elasto-plastic constitutive model defines the plastic and elastic phenomenon caused by loading and unloading that occurs in the heavy oil-reservoir. Several research centers have been focused to design experimental tests to learn more thoroughly the results provided by this model, and the results have been satisfactory. However, laboratory tests are not easy to access in most of cases, so it is necessary to have a numerical simulation model that allows knowing the mechanical behavior of the reservoir associated for any production scenario or strategy.

This paper presents the results from a coupled model, which integrates both the geomechanics and fluid-flow equations for a single-well case using different constitutive models. This model could provide an overall result of the mechanical behavior of unconsolidated sand under production of high viscosity oil. The results comparison for the three considered cases, just fluid flow, an elastic lineal behavior of the rock and finally an elasto-plastic behavior, provides a great difference between the stress-state among cases with a dramatic change in the formation permeability, and therefore in the reservoir pressure.

This numerical model is a useful approximation to improve the characterization of heavy oil reservoirs. As a result, heavy oil reservoirs will have a more successful production intervention or recovery process.
Thermal Induced Fracture Effect with a Lower Cool down Reduction - Case Studies for Ecuador; Villano and CPF Water Disposal Wells
Authors: Andrade A. , Correa R. , Vaca S. , Chango M.
Published: November 2015

The objective of this paper is to display the Thermal induced fracture effect (TIF) observed in Villano water disposal wells by decreasing the injection water temperature by 20°F (Aug 2012) and 10°F (Dec 2013) through to the installation of air-coolers at surface. Furthermore the application of fracture surveillance workflow and the design, execution and results of a controlled temperature and pressure test in CPF disposal well (Apr 2013) are also presented.

The methodology aims to share the results obtained in two different cases ocurred at different times in Villano Field within the Hollin Sandstone formation, allowing improvement of the injectivity in the disposal wells. This work includes comparison of the results and identification of key factors in order to maintain maximum injectivity (100% Producer –Re-Injection water system). Additionally, the implementation of a monitoring program was necessary for a daily surveillance of the injection temperature and well behavior. Finally, field tests performed in another location (CPF) in which the injection temperature was controlled by a heat exchanger. The results were used to evaluate the differences between the documented cases and the Villano TIF cases.

Thermal fracture effects in Villano increased the injection rate by 34K bwpd which resulted in significant savings as new disposal well was not required. The thermal effect was reached with a low temperature reduction (20°F and 10°F), instead of the 50°F+ documented; the maximum reduction in the thermo elastic stress was around 26.5 psi/°F (Propped Fractured well) and 21.7 psi/°F (Non – propped fractured wells) which decreased the injection pressure by 530 psi 217 Psi respectively. Surveillance data suggests that the fractures will remain constant or will continue to grow by maintaining a low temperature. Documented studies advise that the effect is maintained when the temperature is increased however, tests performed in CPF disposal well confirmed that the effect is not permanent if the injection conditions are removed. In the particular cases of Villano and CPF fields, the injectivity is directly proportional to the temperature.