bluuebunny/crossref_metadata_2025 huggingface dataset:
Listening to the Reservoir—Interpreting Data From Permanent Downhole Gauges
Authors: Horne Roland N.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

The permanent downhole pressure gauge is a class of tool that has become popular in the industry. These tools are installed during the well completion and provide a continuous record of pressure changes during production. Permanent downhole gauges (PDGs) have potential to provide more information than is available with traditional well testing, which is carried out for a relatively short duration. PDGs may provide useful information regarding changes in reservoir properties or well conditions with time as the reservoir is produced.

However, interpretation of PDG data is a new problem. Unlike the traditional well test in which "disturbances" in the reservoir (i.e., rate changes) are created and pressure and rates are both known, the changes in rates associated with the record from the PDG may not be known. Moreover, the dynamic changes in the reservoir, along with changes in the flowing temperature or changes in the gauge itself, make the data more complicated to interpret.

Introduction

Developing petroleum resources in an optimal manner requires making many complex decisions on the basis of expectations of future reservoir performance. Central to forecasting reservoir performance is creation and calibration of a reservoir model. These interrelated tasks generally are known as reservoir description and history matching. Most data used for history matching are in the form of surface-measured rates and cumulative volumes of production (oil, gas, and water) and injection (water and gas). However, improving both the creation of a reservoir model and its calibration to replicate measured reservoir history requires collecting measurements from the reservoir itself. In many cases, these downhole data include measurements of pressure, flow rate, and temperature as functions of time. Traditionally, such measurements were made with wireline gauges. However, during the past 20 years, the application of permanently installed gauges has become increasingly common. As of 2006, the number of permanently installed gauges is probably in excess of 10,000 worldwide [Chorneyko (2006) quotes more than 1,000 for one major oil company alone].
Pushing The Limits Of Frac-Pack Operating Envelope
Authors: Furgier J. – N. , Lavoix F. , Lemesnager F.
Published: June 2014

Requirements for Frac-Packing long intervals in highly deviated wells are more and more frequent in many new projects. Although frac packing is a mature technology, its limits of applicability are not well known and are progressively extended by operational experience.

Today, it is a common practice to perform Frac-Pack in 65° deviated well over length of less than 100 ft and to achieve good completion efficiency (mechanical skin less than 5). This is possible with thorough engineering and QA/QC, and when accurate well data are available.

Over the last five years, Frac-Pack operating envelop has been pushed to 70 – 75° deviated wells and to lengths ranging from 100 to 322 ft. The success of such operations depends obviously on some specific precautions:

Enough information about reservoir conditions, geology and rock properties must be available to allow detailed fracture planning. In particular, time must be spent to obtain a representative mini frac and a correct interpretation; Requirements for hydraulic power and pressure rating must be properly assessed. Both the necessary pumping means and the proper down hole equipment (sand screens must be equipped with alternate path system) must be available.

The completion efficiency of such Frac-Pack is not always guaranteed. Global skin may be affected by induced (or not) partial penetration. The longer the interval, the higher the risk.
Gas Pipeline Maintenance: Safety and Environmental Issues for Operations in Highly Sensitive Ecosystems
Authors: Strappa Carla , Garzon Eduardo Tapia
Published: June 2014

The Ramos – Cornejo pipeline carries natural gas along 38 km from the Ramos field, in Northwestern Argentina, to the trunk pipeline network operated by TGN S.A or, alternatively, to a gas processing facility located in Campo Duran. It has a rated capacity of about 7,100,000 m3/d STD and goes through a highly sensitive environment, the "Yungas" or Northwestern Argentina's forest.

This paper focuses on how YPF (a company of Repsol-YPF group), which is responsible for this pipeline maintenance, addresses safety and environmental issues. Due to its unique features, including climate, and native flora and fauna, this location (near national parks and protected areas) requires special procedures.

The above-mentioned procedures are detailed in a maintenance handbook which describes several tasks and steps required to run the operation. Each such step is examined and documented, analyzing how it contributes to safety and environmental soundness. Environmental issues are also reviewed, particularly mitigation actions to deal with potential impacts. YPF's experience with this activity as well as empirical evidence is described.

Finally, a brief guide is proposed for use in this kind of operations in highly sensitive ecosystems.
Integrated Studies on a Conveyor Belt—A New Concept of Study Workflows Based on Stochastic Principles
Authors: Graf T. , Dandekar R. , Amudo C.
Published: June 2014

With multi-processor cluster computing, modular stochastic workflows and a dedicated project team, the turn-around time for project execution has been significantly reduced. Using these concepts, it is now possible to conduct integrated studies successively in a continuous chain of studies, as if they were on a conveyor belt. For example, field development planning studies for ten reservoirs, some with history of more than 20 years have been generated within one year.

The three main enabling technologies for the rapid execution of integrated studies are cluster computing and unique modular workflows that are based on stochastic concepts.

Clusters have been deployed because of its established advantage in improving performance which in this case translates into a significant reduction in simulation times. A modular workflow enables the various tasks in an integrated study to be assigned to project team members, facilitates the flow of task outcomes between project team members and creates enormous flexibility during project execution by permitting tasks to be swapped between members. Furthermore, introducing statistical methods to data handling, history-matching and risk analysis streamlines the activities and reduces the turn-around time for the various tasks.
Formation Mineralogy Impacts Scale Inhibitor Squeeze Designs
Authors: Gdanski Rick
Published: June 2014

Scale inhibitor squeeze designs are often developed using short-core laboratory flow tests for estimating treatment life and fluid/rock compatibility, bottle tests for reservoir fluid/squeeze treatment compatibility, and guidelines for sizing the mainstage and overflush. Laboratory tests provide a relatively high level of successful squeeze designs. However, occasionally squeeze treatments cause unexpected loss of production and short squeeze life. This paper discusses how formation mineralogy can further improve successful designs of squeeze treatments even before laboratory tests are conducted. A radial model has been used to demonstrate key principles of optimizing treatments. Previous work in this laboratory had demonstrated the importance of understanding mineralogy when fluids, such as acid or brine, are injected into sandstone formations. Many of these principles hold true for scale inhibitor squeezes. Understanding the role of formation mineralogy can help avoid unexpected compatibility problems and improve squeeze life.

In general, the mainstage of squeeze treatments should consist of no more than 5% inhibitor product at near-neutral pH. The base fluid should consist of "1-Molar" brine if swellable clays are present in oil-bearing layers of the producing well. The overflush should be sized to provide peak inhibitor returns at 2,000 to 5,000 ppm of scale inhibitor in the early returns of the treatment. As a result, typical overflush volumes range from 2 to 8 times the volume of the mainstage, depending on the formation porosity, total mineral content, and compositional distribution of non-quartz mineralogy. Compatibility of mainstages with formation fluids should be achieved with a preflush, and not by lowering the pH of the mainstage, due to dissolution of calcium carbonate and leaching of aluminum from clays.
Seeking the Ultimate Field Development Using the Well Maturity Index
Authors: Kloosterman H. J. , Herring T. R. , Tull S. J. , Van der Lee J. W.
Published: June 2014

A case study is presented from an oil field in the Sultanate of Oman, operated by Petroleum Development Oman. To date the field has seen limited production under natural depletion (~1% of STOIIP produced). Most of the oil is located in 20-25 m thick oil rims with large gas caps in the reservoirs of the Gharif and Al Khlata formations. A Field Study was kicked off in PDO in 2004, triggered by the results of recent appraisal wells and has substantiated significant additional field potential.

This paper extends previous work [Ref 1] in which we set out the use of Experimental Design for subsurface uncertainties analysis and development options evaluation for an oil field in the Sultanate of Oman. Here, we demonstrate for the first time how the multi-scenario ED modeling results can be taken one step further in Field Development optimisation. We introduce the concept of "Well Maturity Index" which quantifies the impact of subsurface uncertainties on EUR for each well in the selected development. The Well Maturity Index was used to guide decisions on the phasing of development and appraisal drilling and to help formulate a data acquisition programme for the field.

This approach has resulted in an auditable and quantified decision-based plan for maximizing NPV and minimising risk, and adds significant value to the development planning process. This work also provides a natural stepping stone for a quantifiable Value of Information analysis, and scenario planning based on appraisal outcomes. The methodology used is general and should find application in many field development studies..
Automatic Fracture Network Model Update Using Smart Well Data and Artificial Neural Networks
Authors: Al-Anazi A. , Babadagli T.
Published: June 2014

This paper presents a new methodology to continuously update and improve fracture network models. We begin with a hypothetical model whose fracture network parameters and geological information are known. After generating the "exact" fracture network with known characteristics, the data were exported to a reservoir simulator and simulations were run over a period of time. Intelligent wells equipped with downhole multiple pressure and flow sensors were placed throughout the reservoir and put on production. These producers were completed in different fracture zones to create a representative pressure and production response.

We then considered a number of wells of which static and dynamic data were used to model well fracture density. When new wells were drilled, historical and new data were used to update the fracture density using Artificial Neural Networks (ANN). More dynamic data will be provided as well as more static data when additional wells are drilled. The accuracy of the prediction model depends significantly on the representation of the available data of the existing fracture network. The importance of conventional data and smart data prediction capability was also investigated. A highly sensitive input data was selected through forward selection scheme to train the ANN. Well geometric locations were included as a new link in the ANN regression process. Once the relationship between fracture network parameters and well performance data was established, the ANN model was used to predict fracture density at newly drilled locations. Finally, an error analysis through correlation coefficient and percentage absolute relative error performance was performed to examine the accuracy of the proposed inverse modeling methodology.

It was shown that fracture dominated production performance data collected from both conventional and smart wells allow automatically updating the fracture network model. The technique proposed helps in generating another -readily available at no cost- data source for fracture characterization to be used as supplementary to limited 1-D data obtained from well logs and cores.
Optimum Economic Development of Mature Eastern European Oil Fields -Case Study
Authors: Fellner Maximilian , Duta Gabriela , Ingham Jon , Vespan Marina
Published: June 2014

Following the acquisition of 51% of Petrom by OMV in December 2004, the management team saw an opportunity to completely redesign their overall investment appraisal process aiming to bring it to a level comparable with the best in the industry. In particular, with the advent of the Sarbanes Oxley (SOX) legislation in the US, Petrom management wanted to achieve a level of consistency and transparency that would meet or exceed the highest international standards.

The processes in place under state ownership were focused primarily on production maintenance and lacked the economic and financial discipline required to simultaneously maximize return to shareholders. The implementation of a modern project appraisal and investment analysis system was therefore a major imperative of post-acquisition change management. In this situation availability of quality data was a major barrier to progress, however it was felt that establishing a level playing field was one of the keys for success.

Following the implementation of a suitable standard framework a business model was built for the entire Petrom E&P division using commercial software. This model was then used to forecast the outcome of several operational choices against three key strategic targets. The model contained details of more than 1,700 projects and producing fields and allowed Petrom to simulate prioritization or delay of any part of the program while honoring the links and dependencies between individual options. Goal seeking optimizers were used to find solutions that best fulfilled the corporate production target whilst staying within the established regional annual budget expenditures and other KPI's. The analysis ultimately led to selection of projects that would achieve the production and operating expenditure targets whilst requiring well below the anticipated capital budget in two of the three organizational Regions of the Romanian operations.

The paper describes how the application of business modeling practices, that have been applied effectively to long term portfolio decision making, can also be used for near term field development, capital investment, modernisation and budgetary decisions. The implementation stretched the boundaries of current practice and showed that significant insight can be gained; in particular the results show what can be achieved with far less than perfect data. An additional outcome was the accelerated development of several Petrom personnel in the application of modern business methods.
How to Optimise Oil Recovery after almost 60 Years of Production from the Matzen Field, Austria
Authors: Poellitzer Stefan , Gruenwalder Markus , Kienberger Gerhard , Clemens Torsten
Published: June 2014

The Matzen field is one of the largest producing onshore oil fields in Europe. The field consists of multiple stacked reservoirs. The total field Oil Originally in Place (OOIP) is about 190 million m3.

During the last years, a comprehensive effort was undertaken to improve recovery from this field. Integrated studies were performed for the main horizons and the surface facilities.

Within the long production history of the field, more and more reservoirs were found. This resulted in construction of different gathering stations in various areas of the field. Also, the flowline system was constantly modified to be able to produce the different horizons.

The studies of the main horizons revealed that a substantial potential for improved recovery exists in this field. This potential was identified and risked by using assisted history matching. A number of infill drilling locations were found. In addition, potential for acceleration of production was seen.

To maximise the value of the Matzen Field, the approach was taken to completely rebuild the surface facilities. The satellite facilities will be given-up and a new flowline system is currently constructed. The centralised facilities will have a modular setup to enable to increase gross production as needed to accelerate oil production.

The new facility setup will reduce operating costs and allow maximising recovery from this field within the next 30 years. The first results of the new development concept showed an increase of oil production of the main horizon by 30 %.

Furthermore, as part of the simulation study, technical feasibility of using the gas cap of the main field for peak Underground Gas Storage (UGS) was investigated.
A Multidisciplinary Approach Applied to a Mature Field Re-Development, Llanito-Gala Field, Colombia
Authors: Vanegas G. , Lozano E. , Gomez V. , Gonzalez R. , Montt M. , Santacruz R.
Published: June 2014

The Llanito-Gala field, Colombia, is a structurally and stratigraphically complex field in which the determination of productive zones in multilayer shaly sands is hindered by a low-resistivity low-contrast (LRLC) condition. Data acquisition in this field is not straightforward and several operational problems have occurred during its history. Redevelopment of this mature field with over 40 years of production depended on obtaining funding for new drilling while competing against other projects in more prolific areas.

Current technology cannot reduce the uncertainty in fluid identification for this kind of reservoirs, precluding the application of conventional methods for evaluation. The determination of objectives was performed using simple approaches, combining human knowledge with a multidisciplinary real-time work methodology as indispensable resources to minimize risk. Statistical analysis, probabilistic simulation and other basic techniques were used to determine ideal well locations and for outcome prognosis. Prior knowledge and experience acquired during drilling, discussed and analyzed by the team, were used to define well completion strategies.

The fifteen wells proposed were divided into sets of five wells to allow continuous model update and flexibility in the redefinition of drilling and completion strategies. Designing operations accurately and ensuring the preservation of the integrity of the wells proved to be crucial factors in guaranteeing results in terms of oil production. An unexpected 80% of the sands drilled by the new wells corresponded to units not previously drained, increasing the field's proven reserves in almost 5 MMBbl of oil. All new wells are oil producers, and the oil production rate of the field was doubled.

This experience, from the planning stage through to the final evaluation, is documented as a case study that can be used by other teams working under similar scenarios to learn from the strategy, efforts, errors, achievements and lessons learned.
Methodology for Production History Matching of Petroleum Fields Utilizing Logging Saturation Data
Authors: Grecco C. B. , Schiozer D. J.
Published: June 2014

In the production history matching process, the reservoir simulation model is modified in a way that it becomes consistent with production data, keeping the observed restrictions of the geological characterization phase. This technique is limited, mainly in mature fields, when the production history is not reliable, or in the beginning of production, when there are only a few observed data and uncertainties are higher. The development of new saturation data acquisition tools, such as 4D seismic and TDT/TDM logging tools helped to overcome some difficulties in the geologic model construction phase but the great challenge is how to use this data in a way to improve the petroleum production.

History matching methodologies integrated with saturation data from 4D seismic are available in literature but no publications that utilize saturation data obtained from well logging were found. The advantage of the logging tools is the data accuracy but, on the other hand, it is limited to a few feet around the wells. The main objective of this project is to integrate the traditional history matching process with logging saturation data, developing more reliable simulation models and production forecasts. The saturation data is utilized as a new parameter to be matched as well as an auxiliary tool to help to determine critical regions which will be modified. An assisted history matching methodology, utilizing saturation data, streamlines and an optimization algorithm is proposed.

The proposed methodology is applied to a synthetic reservoir model. Parameters of the process are studied and detailed, finding the best way to use the data. The model is also history matched with no saturation information and predictions of the matched models are compared, showing the benefits and restrictions of the new methodology.
Production Strategy Optimization Using Genetic Algorithm and Quality Map
Authors: Maschio Célio , Nakajima Lincoln , Schiozer Denis J.
Published: June 2014

The definition of a production strategy is one of the most important tasks in reservoir management, since it influences projects attractiveness. However, the process to define variables such as well placement, number and type of wells and operational conditions is time-consuming and it demands high computational effort. The use of an optimization algorithm to achieve a good solution can be very valuable to the process but it can also lead to an exhaustive search, demanding a great number of simulations to test many possibilities.

In order to minimize the number of combinations (number of wells and positions), it is proposed the use of the quality map, that is a two dimensional representation of regions with production potential in a reservoir, as a criteria to allocate the wells.

The optimization algorithm used in this work is the genetic algorithm (GA) which is a method based on natural evolution process. The main characteristic of GA is the ability to work in a solution space with non-smooth and non-linear topology, where the traditional methods generally fail.

The methodology proposed in this work is used to optimize production strategies in a realistic reservoir model, defining the number and position of production and injection wells, and the production/injection flow rates. The number of individuals in a population and the number of generations were also varied to evaluate the efficiency of the algorithm.

Results showing the performance of several optimization processes are presented. The influence of the GA parameters control are analyzed and compared.
Minimizing Risk of Gas Escape in Gas Storage by In-Situ Measurement of Gas Threshold Pressure and Optimized Completion Solutions
Authors: Ostrowski L. , Ülker B.
Published: June 2014

Underground gas storage operations and CO2 sequestration in aquifers relay on both proper wellbore construction and sealing function of the cap rock. The potential leakage paths are the migration along the wellbore due to poor cementation and flow through the cap rock. Although 60% of the gas storage wells undergo a costly work-over process to remedy missing cement seal only few operators consider appropriate completion solutions to minimize the risk of losses due to leaky annulus space. The leakage through the cap rock can occur by diffusion and two-phase migration. Modeling of two-phase flow requires the determination of the functional relationship between capillary pressure, relative permeability and saturation. The injected gas moves to the top of the formation below the cap rock due to gravity and density differences. Therefore, the ability of a cap rock to seal fluids is another key parameter for the successful gas storage or long term disposal of CO2 in addition to a proper completion. Capillary pressure data, which are critical for exact prediction of gas leakage through the cap rock are seldom available and yet necessary. In-situ method of gas entry pressure was developed and successfully implemented to help reducing uncertainties in gas leakage predictions. Zonal isolation of cap rock is performed followed by exchange of wellbore liquid by gas. Constant rate injection of gas is then conducted to determine the gas entry pressure into a fully water saturated cap rock. Simulations were performed using this gas threshold entry pressure to investigate the gas leakage amount through the cap rock and along the wellbore for both natural gas and CO2 storage models. It was shown that the uncertainty of predictions could be significantly reduced by using data obtained from in-situ gas threshold determination. Recommended completion solutions for both types of storage operations are presented, which minimize a risk of uncontrolled gas escape.
Selecting an Optimal Field Development Strategy for the Vankor Oilfield Using an Integrated-Asset-Modeling Approach
Authors: Antonenko D. A. , Pavlov V. A. , Surtaev V. N. , Sevastyanova K. K.
Published: June 2014

Two fundamental advances in field development planning took place recently in the last decades. First advance is of an evolutionary type, which allows building large and detail reservoir models and is directly conditioned by the computation capacity growth. Another advance arises from a new revolutionary concept in the field development system design, called the integrated approach. Such approach means that the field development optimization should combine reservoir, well and surface facilities modeling to allow the field development managing based on maximizing technical and economic performance.

The presented study describes an approach to selection of optimal strategy for the Vankor field development. Vankor is a new oil field located in poorly explored area remote from the infrastructure and services. At the time this article was prepared, there were no production wells and surface facilities. Since there are numerous alternatives to optimize field development, the special interest is paid to the field development planning.

Based on the integrated digital model of the Vankor field, the commingled development of two productive zones was studied for the purpose of selecting lifting method, gathering and injection system.
Updating Fault Transmissibilies in Simulations by Successively Adding Data to an Automated Seismic History Matching Processes: A Case Study
Authors: Edris N. R. , Stephen K. D. , Shams A. , Macbeth C.
Published: June 2014

Reservoir management may be improved if the present state of the field is known and if changes may be predicted. The former requires information about current fluid sweep and pressure changes while the latter requires accurate reservoir description and a predictive tool such as a simulation model. With this information, important decisions can then be made including facility maintenance and well optimisation. In some fields, faults control the flow patterns and the update of the transmissiblities has great impact on matching of fluid saturations and pressure to time-lapse seismic (4D) or production history observations. We present an automated history matching method that updates fault transmissibilities by matching 4D seismic predictions from the simulations to observed data. We investigate the impact of successively updating faults by adding new data to our observed dataset and compare this to a single history match where all data is used. We demonstrate the method by applying it to the UK Continental Shelf (UKCS) Schiehallion reservoir. Using an upscaled version of the operator's model, we consider fault transmissibilities as uncertain parameters. Our results show a good match to the observed seismic attributes and dynamic well data with significant improvement to the base case. The best results occur when early data is used in short simulations first as we learn about optimum parameter values and identify the most important parameters. Later data may be added for fine tuning or to explore new parameters.
Interpretation of an Unusual Bubblepoint Pressure Variation in an Offshore Field
Authors: Nasrabadi Hadi , Firoozabadi Abbas , Esposito Rogerio Oliveira , Vieira Alexandre Jaime Mello
Published: June 2014

Bottomhole samples were obtained from eight different wells in an undersaturated offshore oil field. A total of 25 samples were obtained from these wells at various depths. The well temperature data show considerable gradient in both the horizontal and vertical directions. Bubblepoint pressure measurements reveal unusual variations. Some of the wells have a gradual increase in bubblepoint pressure with depth. Some other wells show a decrease after increase and some wells a decrease with depth. The decrease in bubblepoint pressure with depth is the common behavior. There are also vast variations in measured composition, oil density, and the molecular weight of last fraction in different wells.

These variations can be due to compartmentalization and barriers or could be due to gravity, molecular diffusion, thermal diffusion, natural convection or reservoir filling history. Identifying the cause of the variations is important especially in offshore fields. Reservoir compartmentalization can significantly affect the field development plan and the reservoir management.

We have made an analysis of the variations in composition and bubblepoint pressure due to all the above mechanisms in the reservoir with no barriers. The results are different than the observed variations. The reservoir filling effect cannot also explain the large measured variations since calculated mixing time for the fluid is much less than the age of the reservoir. Based on our analysis we conclude existence of barriers in certain parts of the reservoir which explains significant changes in composition and bubblepoint pressure. We also show that thermal diffusion and natural convection can result in an unusual increase in bubblepoint pressure with depth.

To the best of our knowledge this is the first report of this unusual trend in bubblepoint pressure and its interpretation based on the effects of gravity, molecular diffusion, thermal diffusion, natural convection, and reservoir filling history.
Modification of Temperature Prediction Model to Accommodate I-Well Complexities
Authors: Almutairi Fajhan H. , Davies David R.
Published: June 2014

Inflow profiling has proved to be a major application of Distributed Temperature Sensor (DTS) systems. The real-time, downhole temperature data is analyzed by matching the measurements with values predicted by a well thermal model; reducing the uncertainty in the well's production parameters (e.g. permeability, water cut). The accuracy of the resulting inflow profile depends heavily on the accuracy of the temperature prediction model.

Existing wellbore fluid temperature models were developed for conventional wells. This paper focuses on the modification of these temperature models for application to intelligent completions equipped with DTS & Inflow Control Valves. A published temperature prediction model was modified to analyze an intelligent well's geometry i.e. distributed inflow into an annulus, fluid mixing at multiple points etc. The new model was used to demonstrate the effect of water production in an oil and water production environment on the valve's mixing temperature and the tubing's temperature profile.

Our results show that the temperature profile and the mixing valve temperature are over-estimated by current models that represent the inflow of each zone of a multizone I-Wells by a single inflow point. As expected, increasing the number of inflow points within each zone reduces this discrepancy.

This over-estimation reduces the accuracy of inflow profile analysis calculated from the DTS data. Changes in valve temperature in single phase production in a multi-zone intelligent well can be used to indicate the fraction of the zone that is main contributor to zonal inflow e.g. a higher temperature indicates the lower portion on the pay zone is the main contributor and vice versa. A sensitivity study showed that the valve temperatures experience a unique profile depending on which zone is producing water.
The Zatchi B Heavy Oil Reservoir Development: The Unique Challenges of the TAML6 Multilateral Well ZAM-408ML
Authors: Tealdi L. , Baldini D. , Baioni A. , Isella D. , Riccobon L. , Okassa F. , Obondoko G. , Itoua-Konga F. , Malonga H. , Rampoldi M.
Published: June 2014

The Zatchi field, located in the Lower Congo Basin offshore, is a multi-layer reservoir of Cenomanian/Albian age operated by Eni Congo in partnership with Total Congo.

The "Zatchi B" reservoir is a 30 m thick sand characterized by a large accumulation of heavy and highly viscous oil (15° API, 1000 cP) trapped in the marine-transgressive sands of the "Gres de Tchala" formation.

Three aspects make the successful development of such reservoir an extreme challenge: the presence of both bottom water and a gas cap, the very low reservoir pressure, the very high viscosity of the oil. As a matter of fact, over the 19-year life of the field, only three wells were put in production from the "B" layer, with not satisfying results due to the heaviness and viscosity of the oil and the severe problem of gas coning and cresting.

The multilateral technology generally allows increasing the reservoir exposure with fewer wellbores, reducing and spreading the drawdown along the drains reducing the potential for coning. For this reason, in order to improve the reservoir drainage reducing times and costs, the layer B was selected as the optimal candidate for the first multilateral well in the Congo basin: well ZAM 408 ML.

This paper will review the Zatchi B reservoir history and development challenges with a focus on the multilateral well reservoir modeling, the TAML6 completion and ESP artificial lift design. An innovative system for the ZAM-408ML ESP PCP efficiency improvement will be also presented. Furthermore, the challenges encountered during the operations in terms of reservoir properties sampling, operations geology, drilling, completions and production will be discussed in detail.
Enhanced Reservoir Contact using new LWD Technology in Thin Channel Sands
Authors: Hashem Mohamed , Miller Randy , Dossari Saleh M. , Butt Parvez , Hassan Raza , Hussain Sadiq
Published: June 2014

The drilling of development wells in sand stringers involves very thin and sinuous targets. These targets are the channel sand stringers and contain a substantial amount of hydrocarbons. Optimal well placement is a requirement for these very thin reservoirs in order to drain them in a cost effective manner.

Conventional well placement has met with limited success in stringers and the production can be expected to be low from these stringers. A technology driven approach of detecting the formation changes early during drilling was needed. These changes, when addressed, can be translated into maximizing reservoir contact, limiting well-bore tortuosity thus enhancing optimal production.

Due to the uncertainty that is inherently present in the distribution of the channel sands, the prediction of the azimuth of channel meander can now be confidently solidified with new deep and directional electromagnetic measurements (EM) tool. This is a technology which uses directional EM through the use of tilted and transverse current-loop antennas. By detecting the upper and lower conductive shale boundaries the wells have been steered in this very challenging environment of channel sands.

This technology has proven to be a major success in the development of the sand stringers by improving the Net to Gross ratio by more than 50% and hence the longevity and producabilty of the stringer wells as compared to conventional well placement LWD techniques.
The Benefits of Integrated Asset Modeling: Lesson Learned from Field Cases
Authors: Rotondi M. , Cominelli A. , Di Giorgio C. , Rossi R. , Vignati E. , Carati B.
Published: June 2014

Nowadays oilfield development has become more technically and economically challenging and a high degree of interdisciplinary interaction is needed to have an effective and efficient management of the field. The achievement of this goal is made possible only if all the different resources of an organisation work together sharing the same reservoir model. Indeed, the main breakthrough behind Integrated Asset Modeling (IAM) is to combine reservoir, production and surface engineering modeling into an asset management tool that allows the simulation of the whole oilfield system. Though the need and the benefits of IAM were already recognised during the seventies, it is only in the last decade that software tools required to perform integrated production simulation have become available. Coupling dynamic reservoir and surface facility models into a single integrated model may address the following issues: pressure interaction between the surface and the subsurface; mixing of different fluids and flow assurance; accounting for facilities constraints; and identification of system bottlenecks and backpressures. In this way, unnecessary drilling can be avoided, new opportunities can be discovered, optimal artificial lift programs can be implemented to meet production targets.

In this paper the state of the art of IAM tools is reviewed, with emphasis on the solution implemented in our company. Benefits and criticalities are then discussed on the basis of three cases, including integrated models for regional gas production systems, deep water mixed oil-gas assets and gas lifted reservoir. Indeed, it has been noted that integrated surface-subsurface modeling will have a critical impact on field management by offering increased accuracy in forecasting reservoir behaviour and maximising the recovery factor at minimum cost.
Influence of Geological Features on Well Test Behavior
Authors: Mijinyawa A. , Gringarten A. C.
Published: June 2014

Well test analysis is used routinely to determine average reservoir properties with the help of relatively simple interpretation models. Identification and quantification of geologically complex reservoirs is also possible, but requires complex interpretation models often not available in the literature.

This paper investigates four common complex reservoir geometries using numerical simulation, namely: a semi-infinite channel with non-parallel boundaries; a T-shaped channel; a meandering channel with different well locations and meander angles; and a pinch-out boundary. It is shown that all these configurations yield characteristic behaviors in a well test, which can be analyzed as combinations of simpler, known behaviors. A semi-infinite channel with non-parallel sides appears as two sequential wedges; a T-shaped channel (which can be used as a simplified representation of a distributary or meandering channel system) is equivalent to two linear channels, either perpendicular to each other or positioned one after the other. The location of a well in a meandering channel affects the early-late and middle-late time behavior of the pressure and pressure derivative responses in a well test but not the late time behavior. Finally, the well test response of a pinch-out boundary is similar to that of a single sealing fault, but with a longer transition after the derivative main radial flow stabilization.

The overall conclusion is that complex geometries are revealed on the well test pressure derivative by a non-standard transition between the main radial flow derivative stabilization and the late time boundary behavior. This transition gives access to quantitative information related to the complex geometry that is usually ignored in routine well test interpretation.
Simulation of Transient Cuttings Transportation and ECD in Wellbore Drilling
Authors: Costa Suzana Santos , Stuckenbruck Sidney , da Fontoura Sergio A.B. , Martins André Leibsohn
Published: June 2014

Among the costs considered on an oil field exploration, the drilling process related ones constitute a significant share. Consequently, the focus on the removal of cuttings generated by the drilling process, or the hole cleaning operation, is essential.

This operation remains a critical issue in the drilling of high inclination-wells, since the cuttings tend to deposit themselves due to gravity's action, forming a bed in the annular space formed between the drill string and the casing. When this bed takes a sizable fraction of the annular space, it becomes responsible for many problems that appear on the drilling stage, such as premature bit's exhaustion, low rates of penetration, formation fracture, stuck pipe, fluid flow interruption, etc. If this situation is not treated properly, it may cause the loss of the well.

Once the phenomena affecting cuttings transportation, bottom hole pressures and ECD prediction are time dependents, a transient model for the whole trajectory of the wellbore was build. This model can predict the pressures developed in the annular due to the phenomenon that occurs in the drilling process, like bed height increase/decrease, drillpipe movement (surge and swab), increase in the amount of solids caused by rock instability problems and operational parameters changes (increase/decrease in ROP and fluid flow rates).

This paper objective is to present a new transient methodology to simulate the cutting's carrying and annular pressure evaluation on a transient approach and to present some examples of this model. These examples will showcase bed height, cuttings concentration, pressure and ECD curves along time and over the whole trajectory, due to changes in the parameters mentioned above.
Transverse Multi-Fracture Technique in Kitina Highly Deviated Off-Shore Wells
Authors: Pace Giamberardino , Casero Alberto , Tealdi Loris , Obondoko Gaston , Rampoldi Maurizio
Published: June 2014

Brownfield field have been defined as mature field in a state of declining production or reaching the end of their productive lives. Nevertheless these fields provide more than 50% of world's production as well as world's reserves and so it will be for next 20 years. For that reason revitalization of mature fields has to be a "must".

The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic depletion and, in order to maintain the economic operation of their valuable assets, alternative production intervals have been opened to production. Most of these low permeability reservoirs can produce at economic rates only with the application of hydraulic fracturing treatments in a multi-fractured well scenario.

Accurate candidate selection, optimized treatment design, sound reservoir modeling of production forecast represent crucial and interdependent factors for successful economic evaluations.

This paper describes the massive hydraulic fracturing campaign carried out between April and June 2007 on the Kitina 3A reservoir, offshore Congo. Eight hydraulic propped fractures were placed in three re-completed, cased-hole highly deviated wells with very encouraging production increases (stabilized production increase ranging from 2 to 3 times). The transverse multi-fracturing technique was adopted. This technique utilizes a series of packers and frac-ports that are sequentially shifted allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping equipment. All the aspects from candidate selection, pre-job design, on-site operations and post job evaluations with particular focus on the operational challenges encountered are described. Recommendations for the future applications of this stimulation technique are proposed. Furthermore, the challenging theme of forecasting mid-long term production profiles for horizontal, slanted and vertical multi-fractured wells is tackled. Different analytical and numerical models, approaching the task with various methodologies, were applied and tested to define the production profiles of the three candidate wells, which differ in terms of geometry and reservoir properties. On the base of the experience gathered on such wells, some general guidelines were drawn for a wider application.
An Applied Chemical Flooding Simulator and Its Application in Daqing Oilfield
Authors: Chen Guo , Li Ye , Wang Jinmei , Ma Moran , Lu Kewei , Jin Guangzhu , Sun Hongli
Published: June 2014

Daqing Oilfield has conducted various complex chemical improved oil recovery methods in both pilot tests and field applications such as alkali-surfactant-polymer (ASP) flooding, ASP+Foam flooding and multi-polymer flooding, in the meantime, some new process mechanism for various chemical flooding techniques has been rediscovered, for example, polymer elasticity could increase micro-scale oil displacement efficiency, making the existing chemical flooding simulators insufficient to handle these complex chemical flooding process mechanism. In this paper we develop an applied chemical flooding simulator to have capability to simulate various complex chemical flooding processes in Daqing Oilfield. In comparison with existing chemical simulators, the newly incorporated features include the chemical synergistic effect among surfactant, alkali and oil in ASP flooding with ultra-low surfactant concentration, increasing micro-scale oil displacement efficiency by polymer elasticity, multi-polymer commixing flooding process, foam behavior dependent on the reservoir pore structure and the ratio of gas to liquid in foam system, relative permeability that is a function of polymer elasticity and capillary number. The simulator models the other main physicochemical phenomena in chemical flooding process such as convection, dispersion, diffusion, adsorption, aqueous reactions, in-situ generation of surfactant from acidic crude oil, etc.

The solving scheme for the simulator is sequential solution method, deriving pressure equation, saturation equation and concentration equation from mass conservation equation, and then solving the pressure equation implicitly, followed by obtaining the implicit solution of the saturation equation through Newtonian method. For concentration equation, an operator splitting method is employed to split it into a diffusion equation and convection equation, obtaining implicit solution by alternately solving the diffusion and convection equation. The solution procedure for diffusion equation is ADI. The convection equation is discretized using an implicit single point upstream method, by taking advantage of the reservoir flow potential field, to obtain an implicit non-iteration solution algorithm.

The developed model is a 3-D 3-phase (oil, water and gas) and multi-component chemical flooding simulator, having ability to simulate single polymer flooding, multi-polymer flooding, ASP flooding, and ASP+Foam flooding. It has been successfully applied in various chemical flooding simulations. This paper also presents some cases for its application in Daqing Oilfield.