bluuebunny/crossref_metadata_2025 huggingface dataset:
Confidence in Critical Velocity Predictions for Solids Transport
Authors: Soepyan F. B. , Cremaschi S. , Sarica C. , Subramani H. J. , Kouba G. E. , Gao H.
Published: October 2014

Sand is often produced with oil and gas even though sand control practices are used. To successfully transport solids in pipelines, the fluid velocity must exceed the critical velocity. Solids transport models are used to predict this velocity. However, for the same input field or laboratory condition, the models' critical velocity predictions may differ by orders of magnitude. Furthermore, none of the models provide information regarding the confidence in their velocity predictions. This paper introduces a systematic methodology, which selects the appropriate solids transport models for predicting the operational critical velocity envelope to ensure solids transport in the pipe to within a predetermined confidence level. Given a field or laboratory condition as input, the approach generates: (1) velocity predictions and uncertainty bounds of all models to within a predetermined confidence level, (2) recommendation of appropriate models for calculating the critical velocity at the input condition, and (3) impact of the uncertainty of input condition, experimental data, and model on the overall uncertainty bounds. The methodology uses data clustering, model evaluation, optimization, and uncertainty propagation approaches. Based on three Case Studies, the velocity envelopes suggested by the methodology, at the 90% confidence level, are consistent with experimental observations. For input laboratory conditions, which are used for validation purposes, the contributions of model, input condition, and experimental data uncertainties to the velocity prediction uncertainty were between 50 – 90%, 3 – 20%, and 6 – 40%, respectively. If the parameters of the selected models were fine-tuned, for the same input conditions, the above uncertainties contribute about 40 – 90%, 4 – 15%, and 1 – 50%, respectively, to the velocity prediction uncertainty. For an input field condition (the fourth Case Study), the above values become about 35 – 70%, 7 – 25%, and 25 – 45%, respectively; and about 25 – 30%, 30 – 32%, and 40 – 42%, respectively, if the parameters of the models are fine-tuned prior to uncertainty estimation. The results of these Case Studies suggest that for laboratory conditions, most of the uncertainty in a model's critical velocity prediction comes from the model, while for field conditions, the uncertainties of the model, input condition, and data may have nearly equal contributions.
Multilateral Level-5 Dual Long Horizontal Openhole Gravel Pack Completion on the Peregrino Field
Authors: Ranjeva Jean-Michel , Dahl Espen , Martinho Flavio , Gonçalves Bruno , Ramos Astrid
Published: October 2014

Peregrino is an offshore oil field (block BM-C-7) located east of Rio de Janeiro, Brazil in the southwest part of the Campos Basin area. The oil field was discovered in 2004. Statoil Oil and Gas, Brazil has been operating the Peregrino Feld since 2008. The unconsolidated reservoir (Carapebus formation) shows a mid to high permeability and produces heavy oil.

The lower completion design requirements called for a screened completion with long openhole horizontal gravel packs for sand control and production optimization throughout the life of the field. Horizontal openhole lengths ranged from 800 m to 2,300 m for Peregrino producers. To date, 28 producer wells have been drilled and completed with horizontal gravelpacks. Since wells are not free flowing, artificial lift is required, and electric submersible pumps (ESPs) were chosen to perform the artificial lift; therefore, the upper completion architecture was designed with workover capabilities so that the pumps could be changed out as needed.

In order to maximize reservoir drainage, to save the platform's slot availability, and to optimize ESP efficiency, Statoil planned to drill and complete dual horizontal multilateral wells with horizontal gravel packs on each branch that would have the capability for selective production from each lateral section.For Well B05Y1/Y2, both branches were completed with two open holes of 1300 meters and 800 meters, respectively. These were fully gravel packed and had a Level 5 Junction installed.

This paper will describe:

The target zones The gravel-packing challenges The completion base of design The installation sequences The liner-conveyed gravel-pack technique used to gravel pack the lateral bore The TAML level 5 MLT installation The lessons learned.

The successful installation of a dual-bore horizontal gravel-pack completion with a Level 5 Multilateral System offshore was an industry first for Brazil that opened ambitious perspectives for the Peregrino field in terms of increased reservoir drainage that would improve the oil-recovery factor, and thus, the economic gains. This first multilateral well in offshore Brazil is part of the operator's increased oil recovery (IOR) efforts for the Peregrino field. This is also the first multilateral well in Brazil with gravel packs in both branches.
Successful Campaign Using Coiled Tubing to Perforate Five HPHT Wells in the UK Central North Sea
Authors: Taggart Michael , Phan Truong , Murray Lewis , Cassidy Mike
Published: October 2014

This paper details the planning, design and execution of a successful campaign to perforate five HPHT wells, using Coiled Tubing (CT), in the UK Central North Sea. The project goal was to perforate extended intervals, in live well conditions, in one run and leaving no guns or restrictions downhole.

The well conditions presented challenges to the design and operation of CT in this campaign. Challenging factors included:

The use of high yield strength CT (130,000ksi grade material). Wellhead pressure up to 9,000 psi. Bottomhole pressure up to 12,500 psi. Estimated BHT 375° F. Estimated FWHT 320° F. Well depths of 21,000 ft MDRKB. Deployment of up to 1,645 ft of 2 7/8″ perforating guns. Perforating gun string retrieval to surface. No rathole to drop guns due to: Penetration of the reservoir water bearing zone, potentially leading to produced water and scaling issues in later well life. Access required across the formation for data acquisition and reperforation operations. Cost and time involved drilling hard HPHT formations.

Job design was critical to the success of the operation and consideration given to learnings from similar previous operation. This included selection and analysis of CT material, size, wall thickness and managing potential CT collapse pressure following reservoir perforation.

Further analysis, included calculation of CT stretch, circulation pressure, and wellbore solids removal studies.

Reverse circulation through the CT was carried out. This would increase the effectiveness of fluid displacement when creating an underbalance situation prior to perforation. In order to maintain pressure barriers specific tooling was required to minimise the risk during this operation.

The completion design is discussed with specific attention to the process of eliminating the requirement to deploy and recover perforating guns whilst maintaining control of the surface pressure. The ability to maintain a dual pressure barrier within the completion saved considerable time over the conventional method of recovering long gun strings with pressure at the wellhead.

An important element contribution to the success of the operation was the completion of additional equipment tests completed prior to the commencement of operations. The testing demonstrated equipment was fit for purpose and established critical interfaces as well as creating synergies with the multi-vendor delivery team. The fine-tuned operational and procedural aspects of the job and led to several modifications to equipment and procedures. Further testing was completed to confirm functionality the data acquisition, allowing monitoring and recording of pressures, circulation rate and depth control.

The job design, planning, qualification of equipment and the use of dedicated competent personnel lead to the successful perforation campaign of five HPHT wells without any accidents, environmental spills or lost time and within budget.
Multistage Hydraulic Fracturing Using Coiled Tubing-Activated Frac Sleeves: Case Study From The Permian Basin
Authors: Algadi Otman , Filyukov Ruslan , Luna David
Published: October 2014

Tremendous quantities of unconventional hydrocarbon reserves have been discovered globally. These discoveries have increased the total oil and gas reserves worldwide and in the U.S. specifically. However, safely and economically unlocking these hydrocarbons trapped in shale plays and other tight formations require the use of the latest drilling technologies and the best multistage hydraulic fracturing techniques.

Horizontal drilling and multistage hydraulic fracturing have had a great impact on U.S. oil and gas production. Daily crude oil production has increased by an average of 2 million barrels from 2010 to 2013 (EIA 2013). Unconventional reservoir conditions generally mandate the use of hydraulic fracturing to produce commercial volumes of oil and gas. Fracturing technology continues to evolve rapidly and the new technologies primarily focus on making the process more efficient, cost effective and environmentally friendly.

This case study presents an operational review of the successful stimulation of a Bone Spring horizontal well in Lea County, NM. The stimulation treatment consisted of 29 frac stages and used coiled tubing-activated frac sleeves (CTFS) technology in the Permian Basin. This paper discusses the results and information gathered during the execution of the operation.

The CTFS is a cost-effective and efficient multistage fracture stimulation-completion system. The system has been used extensively in Canada. This patented technology effectively reduces the required hydraulic horsepower, fluid usage, and downtime between frac stages. The CTFS is compatible with open-hole or cemented completions and provides full wellbore access without milling for unobstructed production. The bottom hole temperature and pressure are recorded using memory gauges attached to a coiled-tubing (CT)-deployed bottom hole assembly (BHA) for post-treatment analysis and diagnostics. The system provides rapid recovery from screen-outs, minimizing downtime and adding flexibility to treatment design.

In the Permian Basin, the "plug-and-perf" multistage fracturing technique has been predominant for years. However, this technique is costly and time consuming, as it requires fluid and time to pump the wireline BHA down into the horizontal well section, in addition to having to mill-out plugs to initiate production. The CTFS technique, on the other hand, utilizes frac sleeves that are hydraulically opened using a CT BHA, which saves significant amounts of time between stages and reduces fluid consumption. The single frac fluid entry point allows tighter spacing of frac stages and ensures that the fracture is created at the sleeve, which is in contrast to the multi-cluster techniques, in which some zones can remain untreated. The CTFS has been shown to be a fast and effective multistage stimulation technique. The use of this technique efficiently minimized the non-productive time (NPT), considerably reduced the fluid consumption and shortened the post-frac cleanout time.
Modeling of Induced Hydraulically Fractured Wells in Shale Reservoirs Using ‘Branched’ Fractals
Authors: Al-Obaidy R. T. , Gringarten A. C. , Sovetkin V.
Published: October 2014

Reservoir simulation has gradually become one of the most advanced methods for historical performance analysis and production forecasting for most conventional reservoirs. Unconventional fractured reservoirs still present a formidable challenge to simulate. Simplified reservoir modeling techniques are widely used at present. The recent development of liquid rich gas shale fields presents a new spectrum of problems for numerical modeling in terms of adequate description of in-situ rock permeability, geometry of the induced hydraulic fractures and long-term retrograde behaviour of gas condensate.

Most commonly used simulation models of fractured wells rely on multiple transverse planes each representing a single stage hydraulic fracture to form a network of fractures perpendicular to the wellbore (Vincent, 2011). This approach has difficulties in describing pressure distribution along a single fracture and also within the corresponding drainage area. As a result, the magnitude of pressure depletion and condensate drop-out appear uniform across the fracture-reservoir systems. This can often lead to over-estimation of the rock permeability as well as the contacted reservoir volume.

The focus of this research was on the Kaybob rich gas / retrograde gas condensate region of the Duvernay Shale that is currently being developed in Alberta, West Canada. An actual active production well was used to set up simple ‘branched fractal’ simulation models which were aimed to represent alternative topologies of a "typical" induced hydraulic fracture. Fluid properties, well completion information and production data were used to build and history matched the model over the 2-year historical period.

The simulations demonstrated that fracture geometry had a substantial impact on predicted condensate rates for the same amount of gas production. Differences in reservoir pressure patterns around the fracture segment and the resulting variations in condensate bank build-up led to a wide range of the predicted condensate recoveries over a typical life time of a shale gas producer.

The knowledge gained from this research may provide valuable insight into the optimal fracturing design, including selection of fracture spacing and screening available technology to create the necessary fracture geometry in order to maximize condensate recovery from a rich gas condensate shale field.
Ammonia-Based ASP Processes for Gypsum-Containing Reservoirs
Authors: Sharma Himanshu , Weerasooriya Upali , Pope Gary A. , Mohanty Kishore K.
Published: October 2014

In alkali surfactant polymer (ASP) floods, alkali reduces surfactant adsorption and forms in situ surfactant with active oils, thus reducing synthetic surfactant requirement. Many reservoirs, especially carbonates, contain gypsum or anhydrite. In such cases, a conventional alkali like sodium carbonate cannot be used in ASP formulations because it precipitates as calcite. However, it was found that the calcium concentration in the presence of gypsum can be as high as 2000 ppm without causing any precipitation when ammonia is used as the alkali.Ultralow IFT surfactant formulations were obtained in the presence of up to 1200 ppm Ca2+. Propagation of high pH, good oil recovery and low surfactant retention were observed in an ASP coreflood performed in a carbonate core containing gypsum. The Phreeqc geochemical simulator was used for reactive transport modeling and was found to be an effective tool for designing these corefloods. A good match was observed between the measured concentration of the effluent ions from a coreflood experiment and the Phreeqc simulations.
Application of Fuzzy Set Theory and Expert Judgement in Reliability Analysis of the Arctic Oil and Gas Facilities
Authors: Naseri Masoud , Barabady Javad
Published: October 2014

Reliability analysis has various applications in oil and gas processing facilities such as identifying the bottlenecks of the system, quantitative risk assessments, improving system availability and throughput capacity, and optimising maintenance strategies. Reliability performance of a system can be described as a function of operation time and a series of operational conditions. For this purpose, a range of reliability data is required, based on which the reliability function can be modelled. One of the challenges in reliability analysis of Arctic oil and gas facilities is lack of adequate reliability data. The available historical reliability data gathered in normal climate regions may not be appropriate, as they do not include the effects of harsh Arctic operational conditions on system performance.

In this study, expert judgement process is used to modify the mean-time-between-failure (MTBF) of the equipment to include the adverse impacts of Arctic climatic conditions on system performance. Additionally, fuzzy set theory is used to cope with the uncertainties of experts' opinions in both the component- and system-level analyses. For this purpose, a methodology is presented to perform a fuzzy fault tree analysis (FTA) for system reliability assessments. This methodology is further illustrated by a case study. Based on the results of this study, operational conditions can have various adverse effects on the performance of different components. Additionally, expert judgement can be used as an effective method for system reliability analysis, particularly in the design phase where historical data is scarce.
Elastic Anisotropy of Unconventional Shale at Reservoir Conditions - New, Faster Laboratory Characterization Technique
Authors: Jin Guodong , Pérez Héctor González , Agrawal Gaurav , Ali Abdulwahab Zaki , Khodja Mohamed R.
Published: October 2014

Most unconventional shale formations are transversely isotropic with a vertical axis of symmetry. To fully characterize the elastic anisotropy of a transversely isotropic rock, five independent elastic constants are required. In the laboratory, this tranditionally translates to measuring the wave velocities on at least three separate adjacent core plugs with various orientations - one parallel, one perpendicular, and one at 45° to the bedding. However, it is difficult to drill multiple adjacent core plugs with good quality from a whole core of gas shale because of its weakness and brittleness.

This paper presents a simpler, alternative technical lab procedure of characterizing the elastic anisotropy of transversely isotropic rocks from one horizontal core plug only. The plug is cut parallel to the bedding of the whole core. In the test, it is jacketed in a core holder specifically designed to simultaneously measure six wave velocities at each pressure step: axial compressional, two axial shear, radial compressional and two radial shear. By adjusting the relative position of the sample bedding to the radial velocity transducers, variations of wave velocities with angles is determined; thereafter, the five elastic constants and three Thomsen parameters are calculated. For validation, one synthetic rock sample was constructed comprising thin layers of various materials. Three plugs were cut adjacently from the artificial rock in various orientations: one parallel, one perpendicular, and one at 45° to the bedding. The ultrasonic velocity measurements showed that elastic constants derived from the horizontal plug match very well with those from three plugs, confirming that only one horizontal core plug is necessary to analyze the elastic anisotropy of the transversely isotropic media.

The method's feasibility and applicability was demonstrated by performing the elastic anisotropy analysis at room temperature and various confining pressures on two real rock samples: one tight sand plug and one unconventional shale plug. Both plugs are cut horizontally and exhibit characteristics of layers/beddings or a horizontal zone filled with different minerals. For the tight sand plug, wave velocities measured along the axial direction are in good agreement with those from the radial direction. However, the similar phenomenon was not observed for the shale plug. We analyzed the discrepancy using the micro-CT imaging technique. The three-dimensional geometrical structure of the plug was obtained, and the difference was found to be caused by the non-parallelism of the zone to the symmetry axis of the plug.
Fracture Aperture Calculations From Wireline and Logging While Drilling Imaging Tools
Authors: Maeso Carlos , Ponziani Michel , Le Nir Isabelle , Kherroubi Josselin , Quesada Daniel , Dubourg Isabelle , Luthi Stefan , Slob Evert , Fisher Kelvin , Honeyman Les , Brown Randy , Zenned Olfa
Published: October 2014

The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time.

Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors' geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined.

Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.
Myanmar’s Taninthayi Nature Reserve Project (TNRP)
Authors: Htay Tharaphi , Htun Linn Thura
Published: October 2014

Tanintharyi Nature Reserve Project, also known as TNRP is the first collaborative project between Ministry of Environmental Conservation and Forestry, Union of Myanmar and our company PETRONAS together with Total E&P Myanmar since 2004. The TNRP encompasses an area of 1,700sq km and is located in the Taninthayi Region in Dawei District, southern Myanmar. TNRP is a long term project that contributes to Myanmar’s Forest Policy of establishing a 5 per cent protection area of the total country area.The objective of TNRP is not only to help develop protection and sustainable management of significant ecosystems and endangered wildlife system but also take into consideration of improvement of the livelihood of local communities.

The project has recorded several milestones: Nature reserve baseline data collection, Flora survey, Fauna survey and Bird survey. At TNRP, conservation of shifting cultivation had been controlled by development of the community Forestry program. It also developed detailed zoning for effective conservation of reserve; core zone, village use zone, integrated buffer zone and transportation corridor.

Environmental Education programme were conducted at schools, the communities and local authority. Seedling and tree planting program which featured a distribution of seedling and annual tree planting activities during monsoon season around TNR was established. Seedlings were distributed to villagers for free and planted at abandoned area of shifting cultivation.TNRP supports the community through agro-forestry by providing with seedlings and micro-finance programme.

As resulted, comparison of satellite scenes indicated that deforestation and degradation rates were decreasing for the two period 1990-2006 and 2006-2010; 0.008% to 0.001% for deforestation and 0.021% to 0.014% for degradation respectively.
Potential for Harnessing the Heat from a Mature High-Pressure-High-Temperature Oil Field in Italy
Authors: Alimonti Claudio , Falcone Gioia , Liu Xiaolei
Published: October 2014

Significant volumes of water are co-produced with oil and gas in mature hydrocarbon developments. Often, the produced fluids are at high temperatures, and cooling is therefore required. However, because of the large volumes involved, one might consider exploiting the co-produced water's geothermal potential in order to reduce both the field's OPEX and the fossil energy needed to continue extracting the hydrocarbons, and so extend the life of the field by delaying its economic cut-off point. Also, there is scope for eliminating the field abandonment costs for the oil and gas operator, who could hand over the field to a geothermal operator when hydrocarbon production became uneconomic; the geothermal operator would in turn save the initial cost of having to drill and complete wells and install surface facilities.

This paper consists of a preliminary assessment of the potential for geothermal exploitation of the co-produced water from wells in the Villafortuna–Trecate oil field in Italy, which has an aquifer that not only provides pressure support to the reservoir, but also represents an in-situ hydrothermal resource, without the need for external water recirculation.

The study compares three different implementation scenarios for the possible use of the co-produced hot water: direct use in district heating, electric power generation through an Organic Rankine Cycle (ORC) plant, and co-generation of heat and power.

The results suggest that, for the power generation option, a single well draining a cylindrical reservoir drainage area could recover approximately 25 GWh of electric power over a 10 year period with an installed capacity of 500 kW. With the co-generation option, which appeared to be the most appealing, a lower net electrical power of 143 kW per well could be obtained, but at the same time approximately 46 utilities could be served by a 660 kW district heating plant per well.

There remain potential permit and licensing issues associated to the concept of harnessing thermal energy from oil and gas developments, depending on the specific country and legal process. For example, it is often the case that the terms and conditions associated with a geothermal exploitation lease are quite different from a hydrocarbon lease.
A Thorough Investigation of Clean-up Efficiency of Hydraulic Fractured Wells Using Statistical Approaches
Authors: Jamiolahmady M. , Alajmi E. , Nasriani H. R , Ghahri P. , Pichestapong K.
Published: October 2014

Hydraulic fracturing is considered as one of the most effective stimulation techniques to improve recovery especially from unconventional low permeability reservoirs. However this promising stimulation technique sometimes does not respond as expected. Significant amount of work has been dedicated to this topic with ineffective fracturing fluid (FF) clean-up considered as one of the main reasons for this underperformance. However there are still great deals of uncertainties in this area primarily due to large number of parameters affecting FF invasion and its back flow.

This work presents results of 10 different sets of numerical simulations consisting of injection, soaking and production periods for 40960 runs. Each set consists of 4096 runs and investigates the simultaneous impact of 12 pertinent parameters (fracture permeability, matrix permeability (km), end points and exponents of Corey gas and FF relative permeability curves in both matrix and fracture and matrix capillary pressure (Pcm) (depending on interfacial tension (IFT), km and pore size index). Two-level full factorial experimental design and linear response surface statistical approaches were used to sample the variables domain, covering a wide practical range determined with the support of our 11 industrial sponsors, and generate output response.

Results indicate that improvement in FF mobility inside the fracture is the major factor affecting FF cleanup efficiency. In line with this finding, maintaining high Pcm, by retaining high IFT, results in cleaner fracture (lower gas production loss, GPL). That is, increasing IFT retains FF within the matrix and allows more gas to flow freely inside the fracture. This was confirmed by the corresponding saturation map of FF distribution. The effect of Pcm was more pronounced when drawdown was very low and/or soaking time was extended. At very low drawdown and when km was reduced, in a set within its variation range, the effect of the resultant increase of Pcm on GPL was more pronounced than that of the resultant decrease in FF mobility. Generally when injected FF volume increased, larger GPL was observed and reduction of GPL (cleanup) was also slower. As fracture length decreased, cleanup was faster and the effect of fracture pertinent parameters on GPL, compared to those of matrix, decreased.

This works findings allows better evaluation of benefits of this costly operation leading to an optimized design and more efficient ways to improve its performance. For instance, sometimes aiming for a longer fracture, due to its FF poor cleanup performance, is not practically attractive and use of IFT reducing agents to produce more FF during the back flow period, would not have the intended impact to bring back its performance to the desired ideal level.
Expedited Country Startup with a Large Scale Mobilization of CO2 And H2S Equipment and Services for a Major Oil and Gas Company in Latin America
Authors: Daher Elie , Shah Babar , MacDonald Steve , Almeida Daniel
Published: October 2014

The process of establishing a company and operating facilities within Brazil to support a large-scale operation, along with mobilizing 10 offshore packages of CO2 and H2S protection equipment and developing safety professionals, within a tight time frame of 90 days, is a significant challenge. Brazil regulations are unique and distinct, thus requiring much work in establishing a local company with an approved operating facility. The processing periods for attaining document approvals added to time restraint challenges.

The assembly, shipping and importation of the safety equipment had to be managed simultaneously. To ensure that equipment were in compliance with in-country local requirements, a thorough understanding of the rules and regulations was necessary to minimize delays during shipping and importation. Requirements for personnel dictated that a local content had to be in place. Thus, local human resource policies in recruiting, remuneration, development, and termination needed to be understood.

In order to tackle these challenges, a Brazil Task Force composed of multi-cultural senior executives was formed leveraging the support services and field personnel from all corners of the world. Initially, the Brazil Task Force conducted a country needs assessment to identify all the requirements, and to get ‘on the ground’ feel for the business environment. Subsequent to their return, they formulated a strategic implementation plan.

A considerable financial commitment was poured to establish a solid, reliable infrastructure within Brazil, and to procure the required specialized equipment and personnel. A local entity was promptly established in Rio de Janeiro to handle all the legal and financial requirements. The company engaged consultants from several specialized fields to leverage local knowledge and experience. They provided crucial advice on startup of operations specifically on the process of obtaining licenses and permits as well setting up contracts with required local suppliers.

The required safety equipment was assembled leveraging its outstanding manufacturer relations for the prompt delivery of the large volume of equipment for this project. The equipment were documented and packaged efficiently to allow for ease of transport and understanding at customs clearance.

This paper takes a detailed look at the various challenges faced, lessons learned and the key factors that contributed to this project's resounding success.
"LULA" Large Scale Oil Spill Response Exercise: a Unique Opportunity to Test a Full Set of Spilled Oil Monitoring and Modeling Techniques
Authors: Michel C. , Cazes L. , Eygun C. , Page-Jones L. , Huet JY.
Published: October 2014

TOTAL E&P Angola organized, from the 13th to the 15th of November 2013, a large scale oil spill response exercise, called "LULA". The oil spill strategy for the response to a 50 000 bopd blow-out scenario in deep offshore Angola was implemented. Offshore resources were actually deployed and tested, including subsea response with a newly developed subsea dispersant injection system mobilized from Norway and operated from a newly designed and built Light Well Intervention Vessel, and surface response (dispersion, containment and recovery). The implementation of an onshore response plan, encompassing shoreline protection and clean-up, waste management and oiled wildlife response, was simulated. This exercise provided a unique opportunity to mobilize simultaneously a wide array of oil slick monitoring techniques at sea. The assessment of their domains of application and effectiveness was made possible thanks to a special permission given by the Angolan authorities to release a limited amount of crude oil at sea surface.

Daily monitoring was implemented to assess the drift and behavior of the spilled oil and to guide resources during the response operations. Several technologies were tested. Drifting buoys were launched to reflect the oil slick position in near real-time by satellite transmission. Aerial surveillance was carried out by helicopter and by fixed-wings OSRL aircraft (mobilized from Ghana) to provide detailed information about the oil slick (position, shape and location of thickest slicks). These techniques were complemented by one of the latest innovation of the TOTAL Group: the observation balloon BOOST. This balloon, fixed to a supply vessel, provides an overview of the slick from 150 m altitude through a camera which feeds back visible and infrared geo-localized images, thus enabling positioning the response vessels on the thickest parts of the slick and initiating response at first daylight. RADAR imagery was also collected by satellite. A set of techniques enabling 5 days oil spill drift predictions is combined in another Company innovation: SPILLWATCH service, which includes 3D currents and winds forecasts, oil subsea/surface behavior and slick drift modeling, and daily recalibration using the RADAR images.

The results obtained during LULA demonstrated the consistency of the various techniques and confirmed the possibility to track a slick during day and night time.

Being able to follow spilled oil at sea is part of the Company's responsibilities. These tests onsite will considerably improve our good practices and should benefit to the whole Oil & Gas Industry.
Carmon Creek Thermal Field Development Project
Authors: Vannaxay David , Wasden Frederic , Howell Benjamin
Published: October 2014

Carmon Creek is Shell's Heavy Oil In-Situ thermal field development project in Peace River, Alberta, Canada. The Peace River Lease contains some 10 billion barrels of bitumen in-place at a depth of 600 m with viscosity as high as 100,000 cP. The Carmon Creek Phase 1&2 facilities, targeting a subset of this resource, are planned to start-up in 2018 and include oil treatment at 80,000 bod, produced water recycling and steam generation at 50 kt/d and electricity from co-generation at 600 MW. Over the project life-cycle, approximately 7000 dedicated wells (injectors and producers) will be drilled.

The Carmon Creek development concept is a combination of cyclic steam stimulation (CSS) and vertical steam drive (VSD) utilizing vertical and deviated wells in inverted 7-spot patterns at a well spacing of 115m (or 2.8 acres). Produced and imported gas is burnt to generate steam and electricity in co-generation facilities. Electricity is exported to market. After transfer of the thermal energy in the steam the bitumen viscosity is reduced sufficiently enabling production via conventional beam pumps. The produced emulsion is separated into gas, oil and water for treatment in the central processing facilities. Acid gas consisting CO2 and H2S is re-injected to deep disposal and the remaining treated produced gas burned in the co-generation facilities. Treated bitumen is mixed with diluents for pipeline export. Steam generation is fed by recycled water with excess water stored in a saline aquifer, which can be back-produced as needed.

This paper provides an overview of the main aspects of the field development, the challenges related to project delivery for a mega-thermal development and the solutions that were selected to address these challenges.
Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images
Authors: Zhou Yingfang , Helland Johan Olav , Hatzignatiou Dimitrios G.
Published: October 2014

We present a three-phase, mixed-wet capillary bundle model with cross-sections obtained from a segmented 2D rock image, and apply it to simulate gas invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations and saturation paths for the gas invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas-oil, oil-water and gas-water interfaces are determined in the pore cross-sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently based on free energy minimization. The valid configuration change is given by the displacement with the most favorable (that is, the smallest) gas-oil capillary entry pressure. The simulation results show that three-phase oil-water and gas-oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas-oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a non-spreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occurs frequently. The initial water saturation at the end of primary drainage has a significant impact on the gas invasion processes after imbibition. Small initial water saturations yield more oil-wet behavior, whereas large initial water saturations show more water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas-oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.
Preventing Scale Deposition Downhole Using High Frequency Electromagnetic AC Signals from Surface to Enhance Production Offshore Denmark
Authors: Krag Anders , Fergusson Alasdair Macneil , Grainger Martin
Published: October 2014

Mineral scale deposition is a significant impediment to efficient operation of oil and gas facilities. Deposition control strategies include brine demineralisation, chemical inhibition and mechanical intervention. Mitigation costs are highest at offshore locations requiring well intervention and include significant production deferment. Hydrocarbon production in the Danish sector of the North Sea has a number of specific regional challenges as reservoirs are often carbonate with high produced water calcium concentration resulting in a high potential for carbonate scaling. Secondary production techniques such as water injection flooding to maintain pressure are used and sea water is pumped directly into the reservoir introducing sulphate leading to downhole mineral scale deposition of barium sulphate, strontium sulphate etc. The offshore location of production facilities dictates that interventions are expensive and put pressure on valuable offshore bed spaces.

This paper reports results of field application of a recently introduced scale control technology based on high frequency electromagnetic AC signals generated and impressed onto a well head or associated piping conduit. Field trial data is provided from a production well with a history of scaling where production pressure was held back to reduce scaling severity. Field trial data describes the impact of the technology in preventing scale in a high value well. Analysis of the results showed that physical treatment using this alternative approach effectively controlled scale deposition such that the production systems was protected and the production benefits included increased reliability of gas lift valves, cessation of any tubing acid washes and enhancing production. The economic value added and reduction in risk to personnel and emissions are described.

An extended (9 month) pilot test has allowed production to be increased and no mineral scaling has been detected. The results achieved are promising. Stable and no lost production added a value to the producing asset and avoided significant revenue loss to the operator.
Staying the Course with Safely Delivering the Challenges and Opportunities Represented in Subsea Tieback Portfolio in the Gulf of Mexico
Authors: Sharma G. , Moss D.
Published: October 2014

This paper discusses the unique opportunities and strategies for successfully delivering Health, Safety, and Environmental (HSE) performance for Shell's Gulf of Mexico (GoM) Subsea Umbilicals Risers & Flowlines (SURF) Brownfield projects. Successful safety performance is evidenced by the 3+ years of zero recordable incidents for these projects.

The GoM SURF Brownfield projects constitute a portfolio of subsea tiebacks, each with the purpose of bringing new production to existing assets. Although typical project size is less than comparable Greenfield opportunities, these projects carry a high degree of technical and non-technical complexity. Managing the interface between the project and the existing asset, schedule dynamics inherent with multiple Mobile Offshore Drilling Units (MODUs), fragmented project delivery teams comprised of relatively junior staff, and high economic imperatives of project delivery present unique HSE challenges in the tie-back arena.

This paper will present the SURF Brownfield project execution model, which has increased the potential for safe, predictable, and efficient project delivery. Development and deployment of high performing project delivery teams and product delivery lines will be elaborated upon as a key enabler for safe and predictable project delivery. There will also be a discussion on how standardizing the work process supports consistent delivery of safe and predictable project outcomes. Finally, there is information on how the standardization was conceptualized and executed for effective implementation in the SURF community.
Novel Dynamic Diversion Applied in Stimulation of Shale Plays in North Mexico
Authors: Valenzuela A. , Parra P. A. , Gigena L. D. , Weimann M. I. , Villareal R. , Acosta N. L. , Potapova E.
Published: October 2014

In 2010, exploration of gas-rich and possible liquid-rich shale reservoirs began in northern Mexico. The initial challenges as in any exploration project were to demonstrate the availability of reserves and set the foundation for future development of plays. Wells were aimed at the upper cretaceous Eagle Ford formation and at the Jurassic Pimienta formation. While exploration campaign continues, the first development wells have been drilled in some areas. A total of 19 horizontal wells have been drilled and completed by January 2014.

The wells drilled in the latest stage of the exploration campaign in the Pimienta formation presented additional complexity, which led to an undesired trend of increased costs and extended completion times. Also, some of the wells drilled and completed during an earlier stage of the exploration campaign showed a rapid decline in production which directly threatened future development plans. To reverse these trends, a novel dynamic diversion technology for hydraulic fracturing treatments was implemented with positive results. This technology improves distribution of hydraulic fracturing treatments along the horizontal section of the wells, therefore allowing the stimulation of longer perforated intervals at once, ensuring that a great majority of the perforated clusters are efficiently stimulated. The need for mechanical plugs, to isolate the different hydraulic fracturing stages in the wells; the risk associated with pump down of plugs and milling times to remove these plugs were greatly reduced, which results in improved completion times and costs.

This study presents four case histories in which the technology was applied. One of the cases refers to re-fracturing operations of the last 3 stages in a well with a horizontal section of approximately 1,500m which was initially stimulated with 17 hydraulic fracturing stages. The remaining cases refer to the completion of three exploratory wells in which the horizontal section was stimulated with multiple hydraulic fracturing stages using the dynamic diversion technology. The treatments were evaluated using different techniques which mainly included: radioactive tracers and pressure response analysis. Initial results showed evidence of diversion both in pressure response and tracer log analysis, as well as stable production after stimulation. Interpretation of radioactive tracer logs and numerical production forecasting results confirm effectiveness of methodology applied.

The application of this technology can lead to a significant improvement in the efficiency of completions and effectiveness of stimulations of unconventional reservoirs in Mexico and around the world.