bluuebunny/crossref_metadata_2025_split huggingface dataset:
Risk Analysis in the Determination of the Best Exploitation Strategy Using a Calibrated Reservoir-Simulation Model
Authors: Wences A. , Tomas M. 
Published: December 2007

ABSTRACT
This paper introduces a new perspective in reservoir exploitation strategy using risk analysis. In a recent paper1, Acosta introduced an integrated systematic approach to determine the best exploitation strategy from a calibrated deterministic reservoir simulation model. The methodology presented in this work is a step forward, since the deterministic methodology is now combined with stochastic reservoir modeling and economic risk analysis, to improve the decision making process under uncertainty.
A few calibrated reservoir simulation models generated from reservoir characterization techniques, using probabilistic modeling, are used to represent less likely, most probable and optimistic scenarios. Acosta's technique1, 2 is then applied along with an economic evaluation risk analysis program, to determine the optimum exploitation scheme for each scenario.
This new workflow allows the determination of the optimum number of additional wells, their grid locations, as well of assisting to define the most appropriate enhanced recovery process. Key portfolio planning input, such maximum gross rates, production and injection infrastructure requirements, Capex and Opex profiles, are the results from this integrated technical and economical optimization approach.
Reservoir management and strategic decision making process are improved, since both technical and economical risk analyses are considered. The most valuable plan is obtained for all options, along with their overall related uncertainties. Managers, therefore, can select the best alternative for field development, together with an assessment of the key parameters and knowledge to be determined, in order to reduce the project risk.
The Value of Permanent Downhole Pressure Surveillance in the Amherstia/Parang Field, Offshore Trinidad
Authors: Baksh K. 
Published: December 2007

Proposal
The Amherstia platform produces mainly gas from the Amherstia/Parang field offshore Trinidad and was commissioned in 2000 to supply gas to Trinidad's domestic market and Atlantic LNG Trains. The field has approximately 2.8 tcf of proven reserves of which 0.76 tcf have been produced to date. There are 14 wells on production, which peaked at 1.0 bscfd in 2003 with initial well rates averaging 100 mmscfd. The platform also boasted of the first 7-inch horizontal gas well completion in Trinidad with an initial rate of 225 mmscfd. Current production is 600 mmscfd, which feeds a 2.1 bscfd of sales from bpTT's Columbus fields.
Rapid and continuing expansion of the domestic and LNG markets in Trinidad has demanded great emphasis on gas deliverability and reserves assurance. Reservoir surveillance was seen as critical to the fore-mentioned, hence Permanent Downhole Gauges were installed to provide real time pressure and temperature. The data can be accessed through the SCADA system real-time or through an online database.
Data gathered from planned and unplanned shut-ins have been used to frequently update well and material balance models. This data is invaluable in determining gas in place, identification of compartmentalization, reservoir drive mechanisms and generation of reliable deliverability forecasts. Quick identification of any aquifer presence results in necessary actions taken to optimize off take rates to maximize reserves. Drainage volumes have also been tied to geologic and 4-D Seismic data thus optimizing well count.
The high capture frequency database has also enabled pressure transient analysis to be done over the entire pressure history of the wells allowing for the calculation of permeability and frequent updates of completion efficiency (skin and turbulence) as it changes through the life of the well. In addition it is possible to detect boundary (water) movement and provide alternative means of calculation of gas in place, instead of just static shut in pressures as in the traditional material balance technique; typical yearly surveillance cannot facilitate this. This paper will demonstrate the value of permanent downhole pressure surveillance in the Amherstia development by reviewing a number of case histories.
Twenty Years of Steam Injection in Heavy-Oil Fields
Authors: de Souza J. C. , da S. Cursino D. F. , de O. Pádua K. G. 
Published: December 2007

Abstract
This paper reviews the twenty years of steam injection in heavy oil fields of Alto do Rodrigues area. The review includes the beginning, consolidation and expansion of this enhanced recovery method. Main topics involve project management of cycled injection and steam drive along with steady improvements on the quality control of the whole steam generation process. At the end, this work shows the positive impacts on the recovery factor and environmental issues.
New Opportunities in an Exploitation Area - Maria Ines Field - Austral Basin - Argentina
Authors: Gutierrez F. E. , Saccavino L. L. , Cagnolatt M. , Echevarria C. 
Published: December 2007

Proposal
The Maria Ines Field is productive from the M3 reservoir sand and is in a mature stage of exploitation. The purpose of this study was to search for new opportunities near and around productive oil fields.
This integrated work was based on a stratigraphic regional model with additional focus on the structural framework. The facies are developed in an estuarine depositional environment, were 2nd, 3rd and 4th order sequences were recognized. The 4th order hierarchy defines the main reservoir boundaries, whose thickness is controlled by unconformities and flooding surfaces.
The most promising traps were identified below the "known" oil water contact, and a portfolio consisting of step out wells was developed based upon structure size estimates, as well as using a probabilistic calculation of OOIP and risk.
Reservoir Surveillance in Gas Reservoirs, Offshore Trinidad
Authors: Jemmott S. 
Published: December 2007

Proposal
This paper illustrates five examples where the application of reservoir surveillance has improved the understanding and ultimately the performance of gas reservoirs. The reservoirs in question are located off the southeast coast of Trinidad in the Cassia, Flamboyant, Parang, Amherstia and Immortelle fields. Gas is produced to satisfy both Trinidad's domestic and international LNG markets. With the contractual demands brought about by these markets, reservoir surveillance is seen as the key to identifying new well opportunities to sustain supply.
A host of surveillance tools have been employed in Trinidad, including cased hole logging tools such as the reservoir saturation tool (RST) to track movement of fluid contacts, and the production logging tool (PLT) to identify producing intervals and fluid types. Data from both permanent and temporary downhole pressure gauges have been used in material balance modeling and pressure transient analysis to assess reservoir size and drive mechanisms, quantify reserves and deliverability forecasting. Examples of these best practices are discussed within this paper.
Applications of Experimental Design in Reservoir Management of Smart Wells
Authors: Esmaiel T. E. H. 
Published: December 2007

Abstract
Smart well technology (down-hole measurement and control) has progressed significantly over the last few years. Significant research has been done on the application of smart well technology to secondary recovery1,2. Later research has applied experimental design to tertiary recovery including the WAG process3,4. Smart wells and their pro-active application have been shown to provide added value.
This paper aims to determine how the oil price outlook provided by different sources affects the results of the proactive optimization. In a current market of oil price volatility the future outlook of oil prices plays a significant role in the decision making process. Experimental design applications provide screening and response surface designs that facilitate the gradient-based optimization of the WAG process with smart wells in a geologically and economically uncertain environment.
The goal is optimization of the global sweep efficiency under economic constraints through the control of the injection size of each slug, the controlled injection rate of each well, the injection location along the well bore, and the production rates and locations.
The surface response approach allows optimization in an uncertain environment. This smart well approach is compared with conventional wells to determine both the increased value and the reduced uncertainty. This is possible since the surface response models facilitate rapid Monte Carlo simulation.
Novel Ways of Parameterizing the History Matching Problem
Authors: Da Silva F. P. T. , Rodrigues J. R. P. , Paraizo P. L. B. , Romeu R. K. , Peres A. M. M. , Oliveira R. M. , Pinto L. B. , Maschio C. 
Published: December 2007

Abstract
One of the challenges when making a history match study is to find an adequate parameterization for the reservoir model. The main assumptions of the geological characterization should be respect and the influence of parameters on the fluid flow simulation results should be taken into account. On the other hand, the number of parameters should be kept within reasonable bounds in order to make the process viable. In this work, three examples of novel ways to parameterize the history match problem will be shown. Two of them are real field cases and one is a synthetic case based on outcrop data. Common to all examples is the choice of parameters that are related to the geological model building process, such as the variogram in a geostatiscal modeling or correlations between petrophysical properties (permeability x porosity, for instance). In this context, the use of a versatile history matching tool was essential, allowing for a quantitative evaluation for the quality of the match and for managing a larger number of parameters, when comparing to the traditional trial and error procedure. These examples show how the combination of a suitable parameterization with a versatile assisted history matching tool can improve both the quality and the efficiency of the history matching process.
Sand Management of Ultra-High-Rate Gas Wells
Authors: Balgobin C. J. 
Published: December 2007

Abstract
Sand production can pose a significant threat to asset integrity, hydrocarbon control and availability of production. As a result sand management is crucial to protecting commercial interest, safety and the environment. Most of the sand production problems tend to be found in relatively shallow reservoir sands that tend to be unconsolidated. The propensity for sand erosion is exacerbated in ultra high rate gas wells where fluid velocities are typically very high.
The Kapok Field is such an example with reservoirs and fluid velocity that are prone to incipient sand production. Surrounding field history and an appraisal drill stem test (DST) results indicate that sand control will be a major challenge to delivering full well potential thereby maximizing the value of the field reserves. This risk was addressed in all phases of the development from appraisal drilling, to the front-end engineering design and the operation of the field. As a result, the plan of development for the Kapok field ensured that sand production was taken into consideration and therefore measures were put in place to manage sand spanning from well placement in the reservoir and well completion design, topside installation of wear monitors on all chokes, the implementation of two independent types of sand detection systems as redundancy, and managing the field through focused well operating guidelines and adhering to a reservoir surveillance plan.
Kapok Field production is on plateau delivering 1.1 Bcfd of gas and approximately 10,000 barrels of condensate per day that will be exported off the Kapok unmanned satellite platform. Customers requiring this daily volume of gas need the assurance that this gas deliverability is not threatened in any way and gas suppliers need to ensure that this deliverability is not compromised such that both parties maximizes return on their investment in a cost effective manner.
Challenges of the 4D Seismic in the Reservoir Management of Marlim Field
Authors: Ribeiro N. , Steagall D. , Oliveira R. , Formiga L. , Kerber P. , Jaeger M. 
Published: December 2007

Abstract
The seismic 4D (Time-lapse seismic), has been globally used as an effective tool in reservoir management. At Petrobras its use is still incipient. A 4D seismic acquisition is being performed in the Marlim field, Campos Basin, Brazil. The main objective is to identify the fluid flow and the undrained areas in order to optimize the infill drilling wells.
The Marlim giant field is located on the eastern Brazilian coast in water depths varying from 600 to 1100m. The reservoir is characterized by an unconsolidated sandstone turbidite related to the regressive megasequence of the Brazilian eastern continental margin. The average porosity and permeability are 30% and 2000mD, respectively. The production started in 1991 and the water injection in 1994. The production is done through seven platforms.
There are two seismic surveys covering the area. The first one, acquired in 1986, has a poor vertical resolution compared to the second one, registered in 1997. The shooting directions of these two 3D surveys are not the same. For the new survey the parameters was quite the same of the 1997 acquisition.
The studies of technical and economical viability have been showing that it will be a challenge to monitor the front progress of water in the field since the impedance contrast among the remaining oil (19 to 24 degree API) and the water injected is not very high. Another challenge in this acquisition is the overcoming of the amount of production structures, that act as obstacles to the conventional seismic acquisition.
This work presents the feasibility studies for 4D seismic acquisition, the acquisition planning and the expectations of its use in the reservoir management.
Optimization of Drilling Well Stage Using a Pressure Profile 3D Model in Cantarell Field, Gulf of Mexico
Authors: Delgado J. , Sanseviero R. , Zepeda R. , Calderon F. , Lopez A. , Morales J. 
Published: December 2007

Abstract
To execute the drilling well plan in Cantarell field, located in the Gulf of Mexico, Petroleos Mexicanos (PEMEX) is implementing a methodology to get a better control during the drilling stage. This methodology uses the conventional available information and a new pressure profile 3D Model. This model has been generated from available information, such as: logs, geologic/geophysics information, pressure values, and drilling mud weight. The methodology is being implemented and adjusted successfully as follow: construction of new wells by recommending casing setting depth after an abnormal pressure zone, determining an operational window for drilling fluids, identification of transitional pressure zones, analysis of the expected dynamic pressures, and recognition of zones with potential torque and drag problems.
Using Seismic Attributes to Estimate Net Thickness in Pinch–Out Areas – Marlim Deep Water Turbidite Oilfield, Campos Basin
Authors: Oliveira R. M. , da S. Ribeiro N. M. , Johann P. R. S. , Camarao Luciano Formiga , Steagall D. E. , Kerber P. A. , Carvalho M. R. J. 
Published: December 2007

Abstract
The Marlim Field was discovered in 1985, about 100 km off the southeastern Brazilian coast, under water depths between 600 and 1,100 m. It is the largest producing oilfield in Brazil (average 500,000 bdp), containing an original oil-in-place volume of 6.4 billion STB and began to produce in 1991, through a pilot system. The field is exploited through 87 producing wells and 45 injectors connected to 7 production floatation units.
The Marlim reservoir is part of the lowstand systems tract of a third-order sratigraphic sequence, which is associated to an important eustatic, sea level fall of about 25 MMy. The turbidite lobes fill an intra-slope, wide depression developed by down slope gliding of underlying, Aptian evaporites. Reservoir facies comprise amalgamated graded beds of poorly consolidated, unstratified, medium to fine-grained sandstones with very low silt and clay contents. Porosities and permeabilities are relatively homogeneous. The Marlim turbidite system was subdivided into nine production zones, mostly on the basis of stratigraphic discontinuities recognized in well logs and cores.
The eastern margin of the field is fault-bounded with the rest of the field limits defined by sand pinch-out that determines the "zero line" of the reservoir. The pinch-out pattern of the sands depends on a series of geological factors, such as the topography of the substratum, the depositional system characteristics, and the intensity of erosive processes, among others. The way of modelling the pinch-out has an important influence in the oil volume since the pinch-out regions occur in a very extensive area of the Marlim Field. Also it has a significant impact in the success of location, navigation and productivity of horizontal wells positioned in the borders.
Considering that several projects of horizontal wells are expected to be drilled in pinch-out areas, the objective of this paper is to present the correlations between seismic attributes and reservoir properties used to improve the estimate of net thickness in pinch-out areas that are below the limit of seismic resolution.
In-Situ Stress Determination Based Upon Borehole Imaging and Rock-Sample Analyses: A Comparison Among Anelastic Strain Recovery (ASR), Acoustic Velocity, and Acoustic Tomography
Authors: Bloch M. , Freitas S. M. S. , Socorro M. , Soares J. A. , Bacelar C. J. R. 
Published: December 2007

Abstract
The orientation of the horizontal in-situ stresses in an oil well at the Potiguar Basin, Northeast of Brazil, was estimated through three different methods: Anelastic Strain Recovery Test - ASR-3D, wellbore Electrical Micro Imaging - EMI, and acoustic velocities anisotropy - VELAN. A fourth and very promising method for acquiring in-situ stress orientation from rock cores, acoustic tomography, is also presented in this paper. The goal of the work was to compare methods dealing with different sources of data, in order to identify a more reliable, though simple and cheap procedure for inferring the in-situ stress orientation. The three methods had very similar results, finding the maximum horizontal in-situ stress at N42,6E (ASR method); N45E (EMI method); and N42E (VELAN method).
Step Change in Reservoir Simulation Breathes Life Into a Mature Oil Field
Authors: Kromah M. J. , Liou J. , MacDonald D. G. 
Published: December 2007

Proposal
The BP Trinidad and Tobago (bpTT) portfolio of assets consists of six producing gas assets, three mature oil fields and several undeveloped gas fields. In addition to significant efforts to meet a growing gas demand for Trinidad and Tobago's LNG and domestic markets, the focus is currently on optimization of oil production. Understanding the uncertainties and optimizing depletion plans is key to successful reservoir management in gas and oil fields.
BpTT uses reservoir simulation to history match and then predict future reservoir performance from highly faulted, stacked sands in Trinidad. Traditionally, a reservoir engineer spends a significant portion of the project time in the construction and history match of the reservoir model to gain confidence for performance prediction. Due to time and resource constraints this generally means that only one model is history-matched. A handful of single parametric uncertainties might be investigated, but decisions are frequently based on the one model thought to be most likely.
BpTT began applying BP's Top-Down Reservoir Modeling (TDRM) philosophy [Williams, et al] in October 2003. TDRM uses a genetic algorithm to assist the engineer in building multiple history matches of the dynamic data based on a user-defined precision, ranges and probability distributions for key input uncertainties. This workflow incorporates a variety of reservoir uncertainties in multiple, probable reservoir models, all of which match the production history within specified precision. Future field and well performance is then optimized by evaluating a range of potential outcomes, rather than by prediction from one single description, as often seen in a traditional manual modeling approach.
This paper relates the successful use of TDRM in bpTT for optimization of infill well locations in a mature oil field. It includes the history match of 30-years of production from 13 wells in the Teak field (Figure 1). The TDRM cycle including history match and prediction was completed in three weeks. The study used multiple scenarios with 16 history-matched models to broaden the scope of analysis of the reservoirs in a time efficient manner.
Assessment of Intermittent Gas Lift Performance Through Simultaneous and Coupled Dynamic Simulation
Authors: Filho C. O. C. , Bordalo S. N. 
Published: December 2007

Abstract
The assessment of Intermittent Gas Lift (IGL) by computer calculations using the mechanistic models found in the literature usually approaches the IGL's operating cycle as a sequence of independent non-interacting stages, occurring back-to-back, without overlapping in time; that approach restricts the system analysis to the limited range of operational conditions when such particular behavior indeed exists. In fact, out of such range, some stages of the IGL cycle may be rather simultaneous than sequential, as previously assumed. This paper presents a new IGL mechanistic model and simulation scheme to consider the possible occurrence of both sequential and simultaneous stages throughout the IGL cycles. The dynamics of the IGL cycles is assessed through a simultaneous and coupled variable set of non-linear algebraic and time-differential equations, interactively defined on the run and solved according to the ongoing stages of the IGL cycle. A case study for a typical IGL well, producing from a low productivity reservoir partially depleted, at different operational conditions, shows how the IGL computer simulator can help the operator to set up the IGL parameters to maximize the well production or its economic gain.
The Study of Plurigaussian Simulation's Lithotype Rule in Reservoir Characterization Process
Authors: Normando M. N. , Remacre A. Z. , Sancevero S. S. 
Published: December 2007

Abstract
This paper proposes to evaluate the reservoir characterization of a mature field using advanced geostatistical techniques. In the reservoir characterization process, the lithologic modeling is an essential stage because it will be work as a framework for petrophysical modeling. The objective of this work is to study the impact of the lithotype rule on the connected facies volume through the plurigaussian algorithm. The interesting advantage for the PGS is the rule function, in this paper we analyze different lithotypes rule and their impact on the volume through the connectivity study using the Hoshen-Kopelman algorithm. As results, it was possible to note that the plurigaussian simulation algorithm presented a good capacity to reproduce the initial reservoir characteristics because it respect the lithofacies proportion, proportion matrix and the lithotype rule and was possible noted too that the lithotype rule present a important constrained to the simulation method. In the continuation of this study we can fill the model with the petrophysical properties and saturation data and observed in fluid flow simulation the impact of the lithologic modeling in reservoir characterization processes.