bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of the Future Exploration and Oil Production in the Brazilian Energy Matrix
Authors: Dias Marques J. B. , Avansi G. D. , Trevisan O. V. , Schiozer D. J. 
Published: June 2012

Abstract
The global energy production reflects an excessive percentage of non-renewable energy. Therefore, a great volume of investment on renewable energy became a serious matter in order to mitigate the damage caused by the consumption of energy from fossil sources. On the other hand, Brazil’s oil companies are living a decisive moment in terms of investments in energy bases, because there is a great demand for capital resources to develop the latest discoveries of enormous non-renewable supplies. In this context, this paper describes the impact of the projects announced by the oil and gas industries in the Brazilian energy matrix. The data comes from the plans presented by the major oil companies that operate in Brazil basins, mainly in pre-salt region, and from reports published by EPE (Energy Research Company – Government of Brazil).
This work involves projections from 2011 to 2020 and it was made assuming three global economic scenarios: recession, stability and economic growth. Projections are treated in a comprehensive knowledge by a simple econometric model and based on the investments announced by the oil industry of the country. Studies take into account the fossil and renewable energy projections under assumptions from the Ten Year Plan for Energy Expansion in 2020 produced by the National Council for Energy Policy (CNPE, in the Portuguese-language acronym).
The results indicate viable economic projects in the renewable energy for the Brazilian oil and gas companies (energy corporations), primarily biofuels, wind and solar power, in the expense of some oil production projects in their portfolios. Brazil is experiencing a great time to develop the renewable energy sources that is made by other countries and if these changes accelerate, it will be the potential to improve its economy by creating millions of jobs.
As main conclusion, the decisions on investment in renewable energy with capital acquired from the pre-salt projects will determine the future of the Brazilian energy matrix. The main goal of this paper is to indicate a transition to a cleaner energy matrix considering an alternative investment plan, and show some fundamental concepts to illustrate how the renewable energy can be important for the oil and gas companies’ subsistence in the next generations.
Design Considerations for Oil-Based, Squeeze Cement Slurries to Prevent Unwanted Fluid Production: Methods of Slurry Performance Evaluation and Potential Formulation Improvements
Authors: Reddy B. R. , Eoff Larry 
Published: June 2012

Abstract
Nonaqueous cement slurries have been used for many years to prevent unwanted water or gas production and to repair holes/cracks or other pathways that could have formed in the casing, cement column, or at the interface. Such slurries were forced or squeezed into flow channels and allowed to contact water being produced or otherwise inherently present. Exposure of cement to water presumably allows for setting of cement, thereby plugging the flow pathway. These nonaqueous cement slurries primarily contained cement, a nonaqueous fluid, and an oil-wetting surfactant. It was generally assumed that contact between cement and water allowed setting of the entire cement mass with ensuing good strength development, even though an efficient dynamic mixing of cement and water under downhole conditions is unlikely. In the laboratory, this is typically demonstrated by mixing (by means of agitation) the slurry and the required amount of water, allowing it to set at well temperatures and measuring strengths.
Laboratory mixing under quiescent conditions by addition of water to the top of nonaqueous cement slurry with no agitation, and allowing it to cure for many days, demonstrated setting of cement only at the interface as a thin solid film, while the remaining slurry was unset. It was not obvious whether the presence of set cement at the fluid interface prevented further ingress of water into the cement slurry, or if the cement particles in the bulk slurry remained too oil wet to allow hydration reactions. It was also not obvious whether a totally quiescent, totally dynamic, or an intermediate level contact between water and cement slurry truly simulated the downhole situation, accounting for the success of the technology. A surfactant combination was designed to allow deeper penetration of water into cement slurry under quiescent conditions. Details are presented.
Success in Production Estimation in High Profile Deepwater Well Using Dynamic Formation Testers
Authors: Aguilera L. E. , Flamenco F. J. , Contreras J. E. , Urbina M. R. , Fuenleal N. A. , De Nicolais N. Y. , Olivo M. A. , Miguel F. 
Published: June 2012

Abstract
Typically the reservoir evaluation in deep water wells (DWW) drilled by Petroleos Mexicanos (PEMEX) in southern Gulf of Mexico has been made conventionally using Drill Stem Testing (DST) operations that can take up to 23 days. This represents a significant investment in cost and time to the operator in their effort to evaluate reservoirs. The challenge was to evaluate more accurately and efficiently to reduce costs and improve reservoir characterization in these deepwater plays.
In this paper, wireline formation testers (FT) are used in openhole DWW for a variety of applications including characterization of the fluids and determination of key reservoir parameters by interval pressure transient testing (IPTT), also referred to as a mini-DST. Real-time monitoring, analysis and job optimization by senior technologists are essential steps in performing a successful logging program. Historically, the wireline programs to evaluate the zones of interest in the Tertiary approximated 8 days that included several gas zones. The new protocol brought an operational advantage to PEMEX by reducing the time required to identify and characterize zones of interest compared with conventional methods. The results included optimization of the production test programs and reduced time/costs for the well production testing stage.
The project has four major steps:
The first stage includes the identification of gas bearing sandstones and will determine the preliminary program. The highly laminated structures are evaluated with special wireline logs that include nuclear magnetic resonance (NMR), high resolution imaging and elemental capture spectrometry. After the zones are identified, the pressure profile will be analyzed with a PressureExpress (XPT) tool that is wireline combinable and allows for efficient pressure formation testing.
In the second stage, the pressure gradients are evaluated resulting in fluid types in the reservoir and mobilities for each flow unit. These results will be used to define the Mini DST stations.
The third phase involves the use of the Modular Formation Dynamics Tester (MDT) with the Live Fluid Analyzers (LFA) to characterize the fluid type in each layer. Formation fluid samples are taken according to the program’s acquisition priorities. The dual packer MDT module allows for isolating each individual layer to perform mini-DST’s that can be used to evaluate and determine the formation’s permeability and skin factor.
Finally a nodal analysis was performed using the permeability values from mini-DST. The results showed very good agreement between the rate predictions from the MDT fluid and pressure data versus the conventional DST results. This helped Pemex in strategic forecasting of production rates and reserves classification while saving rig time.
Maximizing Reservoir Exposure with Proactive Well Placement in High Geological Complexity Field of Venezuelan Orinoco Belt
Authors: Castañeda Luis , León Maryesther , Meunier Antoine , Lara Manuel , Herrera Yoanna , Granado Miguel 
Published: June 2012

Abstract
In 2010, Petrolera Indovenezolana S.A. (PIV), a joint venture between Corporación Venezolana del Petróleo (CVP) and the Indian company ONGC Videsh Limited (OVL), started planning for two horizontal wells in the Norte Zuata (San Cristóbal) field in the Orinoco belt of eastern Venezuela. The focus for this campaign was to evaluate the productivity of horizontal wells in thin sands and avoid areas of complex geology because of the high uncertainty in the structural behavior, applying technology that provided absolute control of the drilling process into the Oficina formation.
Within the Oficina formation, thin sand reservoirs with variations in thickness and dip, geologically facies changes and subseismic faults presented the main challenge to geosteering a horizontal well. Because the project faced high geological uncertainties, a pilot hole was drilled as the first stage in the first well to verify the structural levels and the continuity of the sand bodies.
To achieve the above challenges, the combination of a rotary steerable system (RSS) "point-the-bit" and a deep azimuthal electromagnetic resistivity tool (DAEMR) was used. The measurements provided accurate information to the well-placement engineers for proactive decisions in real time, mitigating the possible loss of the target by these geologic uncertainties.
High-quality and valuable data for real time geological model update were the expected results obtained from the effort made by PIV in the Norte Zuata (San Cristóbal) field, and the data showed the oil-producing potential of one of the main reservoir (Sand F, G). This application of high-tier technologies demonstrated that drilling and data measurements can be improved and optimized to yield added value for reservoir development and 100% net to gross (NTG) targets. This reduces operational cost, makes it possible to drill in the right place the first time, and pushes forward the limit of the achievable in terms of reservoir exposure.
3D3C Seismic Acquisition in Petrocedeño Field, Located in the Junin Area of the Orinoco Heavy Oil Belt, Venezuela. Seismic Designed for Well Implementation and Reservoir Characterization in a Fluvial-Deltaic Environment
Authors: Concepcion Monica , Sanchez Ruben , Perez Abelardo , Suniaga Jose , Vale Jesus , Cova Raul 
Published: June 2012

Abstract
Petrocedeño block, located in the Junin Area of the Orinoco Heavy Oil Belt, is composed of the Main and South areas, and it has been drilled by more than 660 horizontal wells in a fluvial-deltaic environment using real time monitoring, and taking into account the response of gamma ray and resistivity logs and the structure of the seismic reflectors. The Main Area is about 324 Km2 and is covered by 3D seismic acquired in 1998 with a bin size of 15 m x 15 m, a nominal fold of 20 and a vertical resolution of 15 m.
Although the two drilling campaigns has been successful, every day the challenge to identify and to drill new targets is bigger, even with the incorporation of new technologies such as azimutal resistivity tools because the sand bodies are thinner, lateral facies variations are found more often and collision problems has increased. For those matters the improvement of the pre-existing seismic data with a reprocessing in the Main Area and the design of a new seismic in the South Area became a necessity. With the aim of drilling around 200 wells in the South Area, it was performed in 2011 the acquisition of a 3D3C seismic survey of 91 Km2, the first industrial 3D3C in the Orinoco Heavy Oil Belt, with the following characteristics: the use of DSUs, a record length of 8 seconds, a bin size of 10 m x 10 m and a nominal fold of 66. Parameters and characteristics were optimized from previous 3D3C pilots to improve the quality but also to perform elastic inversions from PP and PS seismic waves to better understand the subsurface and to get a reliable reservoir characterization.
A PP seismic Fast Track has been produced and has been used to start the delineation (vertical and slanted stratigraphic wells) and the development programs of the South Area, thus proving immediately its added value for Petrocedeño.
The lessons learned during the seismic design and acquisition will be useful to the future acquisitions in the Orinoco Heavy Oil Belt.
Resource Potential of Natural Gas Hydrate Deposits Offshore Trinidad
Authors: Greig-Jones Shelly-Ann , Marcelle-De Silva J. , Thomas S. 
Published: June 2012

Abstract
Seismic data and gravity cores indicate that natural gas hydrate deposits are present in the Columbus Basin off the East Coast of Trinidad. These data led to the initiation of a research program aimed at delineating and characterizing this unconventional resource. Already the areal extents of deposits in two offshore blocks have been estimated. In this study, the theoretical thickness of the hydrate stability zone for one of the blocks was estimated and additional reservoir properties collated from globally located hydrate-bearing strata. These data were used to conduct a parametric study on the potential volume of natural gas in the block.
Quantification of this unconventional gas resource is important since natural gas is a premium fuel and its use is likely to increase in the short and medium term. Factors contributing to this phenomenon are (i) the increasing global energy demand, (ii) natural gas is environmentally friendlier than oil and coal in terms of total emissions, and (iii) oil and coal, which are high carbon fuels, and greater contributors to global warming. In addition, international interest stems from the fact that gas hydrate deposits are affected by temperature and pressure, and release of methane from these deposits can occur if there are certain changes to these conditions. This could impact oceanic and atmospheric chemistry, and in due course climate.
The data collated from the globally located hydrate-bearing strata indicated that porosities were generally greater than 16%, and hydrate saturations were as high as 80%. These data along with the theoretical thickness of the gas hydrate stability zone indicated that the potential volume of natural gas in situ may be greater than 1 TCF.
This finding is significant since if the technical challenges associated with producing this unconventional resource are overcome, the natural gas stored in this hydrate deposit represents a potential additional source of gas which can be used to help meet Trinidad and Tobago‟s future energy needs.
A Greater Dolphin Area Case Study Part 1: Defining Geological Uncertainty
Authors: Taylor K. S. , Kalita N. , Dowlath J. , Jegede O. , Ameerali R. 
Published: June 2012

Abstract
The Dolphin Field is located in the East Coast Marine Area, approximately 60km off Trinidad. It comprises a 5,000 feet succession of stacked, unconsolidated, Pleistocene shoreface-deltaic sandstones and mudstones lying within a three-way dip, fault closure. The field is complicated by poor seismic data due to gas attenuation, fault shadow effects, large velocity variations and noise in the overburden. As a result the use of seismic amplitudes for fluid determination is unreliable and fault interpretation problematic.
Despite over 15 years of production, 5 exploration wells and 13 development wells there remains a high level of subsurface uncertainty. Specific areas of uncertainties include: zones of poor correlation as a result of large-scale sediment deformation; the configuration and sealing properties of both structural and syn-sedimentary faults; the effects of thin-bedded deposits (forming over 50% of the Dolphin reservoir intervals) on reservoir pay and connectivity; and the absence of all but one proven Gas Water Contact (GWC).
Defining the range of these uncertainties has a key impact on the range of GIIP outcomes, the resultant development plan and subsequent reservoir management. This paper will discuss the challenges and impact of these uncertainties on the Dolphin Field. The uncertainties identified on Dolphin form the basis for uncertainty planning in the development of subsequent analogous greenfields also within the Greater Dolphin Area.
A Greater Dolphin Area Case Study Part 2: Streamlining Subsurface Uncertainty for Business Value
Authors: Persad Shelley , Velarde Javier , Lerza Alejandro , Taylor Katy 
Published: June 2012

Abstract
Calculating and determining a range of Gas Initially In Place (GIIP) is one of the major challenges faced when optimizing a field development plan. Desired outcomes can be further complicated by geological characteristics which are uncertain and difficult to quantify; to the point where a physical solution is unattainable without the use of inappropriate and complicated software applications. Plackett-Burman Experimental Design (P-B ED) is a published and an innovative process which is simple, logical and efficient in managing uncertainty and appropriately defining the range of possible outcomes by utilizing simple, every day and user friendly software. PB ED allows for effective planning and mitigation for the most likely outcome and the least. The geological uncertainties incorporated in the analysis are described in Part 1 of the Greater Dolphin Area Case Studies; SPE 158545.
The P-B ED workflow was applied to determine the range of GIIP for the Starfish field. Starfish is currently not on production and is located off the East Coast of Trinidad and is being considered for development. It is owned as a joint venture between Chevron and BG Trinidad and Tobago (operator). One of the main objectives of this process was to identify the P10, P50 and P90 geo-models which are then used for dynamic modeling and field development planning.
The Unconstrained Development Study (UDS) process was utilized for the field development planning of Starfish. A UDS is a process used to determine the optimum number of wells and their locations to develop a field. The P50 dynamic model was populated with hundreds of wells which were subsequently eliminated based on well performance and water breakthrough. This is an iterative process which has been recognized as an effective workflow for field development planning. Once the P50 reservoir outcome was optimized, both P10 and P90 geo-models were tested to ensure that the proposed development plan was also valid for the geological range. After applying the UDS process; it was determined that four wells were required to optimally develop the field. This paper discusses the Experimental Design and UDS workflows, summarizes the lessons learned and recommends best practice for field development optimal recovery efficiency.
Formation Pressure Estimation and Its Impact On Well Design: A Case Study From The Greater Dolphin Area
Authors: Ameerali R. , Saisbhan A. , Adeleke A. , Harripersad N. , Parotidis M. 
Published: June 2012

Abstract
Pore pressure studies have been a key consideration in well design; both from a drilling design and well deliverability perspective. In the drilling of an exploration opportunity, and in the absence of direct pressure measurements, pore pressure estimation becomes even more critical in the delivery of a safe, cost effective and potentially productive well.
In a previously drilled key well in the Greater Dolphin Area there were no direct pressure measurements taken through one of the tested zones where there is potential for an updip accumulation. To fully appreciate this exploration opportunity, pore pressure estimation is required for both well design and subsequent well cost assumptions.
Given the lack of pressure data for this prospect, pressure uncertainty ranges, supplemented by analogue well data feeding into a geomechanical model were utilized for well design. The geomechanical study defined the appropriate mud weight windows and guided the casing design. This pore pressure analysis also fed into the estimation of production rates and safe operating drawdown envelopes which are critical to the delivery of highly productive wells.
Assumptions on the well design and the expected production rate provided the basis of drilling duration and cost and thus the economic viability of pursuing the prospect. Through this uncertainty management, this exploration opportunity, if deemed viable, can be included in future development programs and if successful, add to the gas reserves of the Greater Dolphin Area.
Leaseout/Farmout Operations in Trinidad - Past, Present and Future
Authors: Ramroopsingh A. , Ramgattie C. 
Published: June 2012

Abstract
The market decline of the late 1980’s resulted in a number of multinational companies retreating from the local oil production scene on the island of Trinidad and Tobago. As such, the state-owned Oil Company at the time was left with over 5000 inactive wells and a large amount of idle equipment such as well servicing rigs, trucks and pumps. The Government of Trinidad and Tobago in a bid to rejuvenate the declining industry issued the mandate that small land based fields which were uneconomical to be produced from should be leased and farmed out to smaller independent local operators in a bid to augment production-a policy that has remained true until the present.
This study reviews the main elements and differences of the Farmout and Lease operatorship as well as highlights the successes and provides suggestions for future roles. The major difference between the LO/FO operations is that with the lease operations, only the well is leased out and the operator has limited rights for the development of petroleum resources in the block. Production is generally confined to the formation across which the well was initially perforated. As a result, there is no drilling obligation. With the Farmout operatorship the operator has unlimited rights to petroleum development in the block at any depth and also is required to drill new wells to develop these resources. This in turn affects the Capital Expenditure (CAPEX) as the type and diversity of expertise required for the operatorship varies for each. During the period 1991 to 1999 the Leaseout program was responsible for the reactivation of 25 dormant blocks. In the same period the Farmout program was responsible for increased activity from 121 wells; 85 of which were newly drilled.
The Leaseout program has shown over 24 MMBBLS of oil recovered to date with the average production for the year 2010 being 4870 bopd. This represents 5.4% of the country’s average daily production. The Farmout program has shown 8MMBBLS of oil recovered to date with an average rate of 1650 bopd in 2010 (1.8% contributions). Developments in these programs include the legal modification of contracts in the form of the IPSC (Incremental Production Sharing Contracts) introduced in 2010.
The future of the programs hold potential for expansion of operations into marine-area and small scale steam flooding and CO2 injection targeting smaller pockets of hydrocarbons on-land and stranded gas offshore. But there will be the need for technical skills to be acquired and passed on if such ventures are to be undertaken successfully and economically.