bluuebunny/crossref_metadata_2025 huggingface dataset:
Getting the Right Seismic Data for the Right Characterization Objective
Authors: Paternoster Benoit , Pagliccia Bruno
Published: November 2012

Reservoir characterization is the main target of seismic processing in UAE to guide Field developments. Delivering the data quality required to meet such an expectation is very challenging and difficult to assess objectively.

The basic requirement is that data are processed in a way which ensures that the propagating wavelet has constant properties. Its amplitude, phase and frequency content must be as stable as possible across the area and depth interval of the field. Often, these very same conditions also apply to the incidence and/or azimuthal angle dimensions of the data in order to be able to apply dedicated reservoir characterization workflows.

Common practice is to use seismic-to-well ties for quality control. More than often, they are unstable and parsimonious. Complementary approaches must be used. TOTAL has devised a workflow which helps assess the progress of seismic processing via a set of spatially extensive attributes.

The very first step of this workflow consists in: defining directions for improvement with the interpreter,translating them into attributes relevant to signal characteristics to be quantified.

The second step consists in: setting milestones at the relevant steps of the processing sequence,quantifying the selected parameters with intermediate migrated 3D volumes at these milestones.

When possible, the same parameters have been extracted beforehand from vintage seismic dataset; relative scores can thus be established to monitor the progress of the newest dataset.

Attributes which can be mapped are privileged so that stationarity can be visualized and quantified. At any time during the (re)processing project, they can be confronted with other interpretative information.

Beyond providing objective quantifications, this workflow induces a strong commitment of the interpreter to the processing project at all stages. It yields confidence that the final dataset is fit for purpose and ready for reservoir characterization.
State of the Art of Geoscience and Reservoir Integrated Study for Eor Co2 Pilot Implementation: Example of a Giant Carbonate Reservoir of Arabian Gulf UAE
Authors: Saniez Jérôme , VandeBeuque Sabrina , Ekpenyong Daniel Eyo , Bastos Nadia , Wantong Paterne , Salley Baptiste , Al-Ameri Ammar Faqqas , Al Katheeri Abdulla , Al-Yafei Arafat
Published: November 2012

In the context of global warming, CO2 capture is one of the explored solutions for greenhouse gas emission mitigation. Its injection in oil fields is one of the EOR schemes adapted to the Middle East carbonate reservoirs. A very high ultimate oil recovery is expected with such a process. A proper design to develop full field EOR CO2 is yet to be found and may be fulfilled through the implementation of one or several pilots.

This study of EOR CO2 pilot implementation required a geosciences, reservoir and surface integrated work in order to place it in some robust and promising locations. A static and dynamic synthesis was performed to understand and better capture the structural context of the field and its level of production maturity. The major risks were taken into account for the selection thanks to a complete synthesis of the available data from the core scale to the surface facilities. An adequate methodology was developed to narrow down the possible locations from the field extent (several hundred km2) to only a few squared kilometers of interest. The field was divided in 6 km2 squares (called "locators") for which a two step selection process was applied. In the first step, the geological typology of the reservoirs and their dynamic statuses at the locator level were defined. Then the risks associated to CO2 injection were assessed. At the end of this step, the selected locators were the less risky ones, representating each geological typology. In the second step, the locators were studied more thoroughly with the evaluation of the level of knowledge illustrating the amount and quality of data available; a geological variability study on permeability was also performed on each area. Finally the surface constraints were incorporated to prevent any incompatibilities with the current or future facilities. This second step provided another sub-selection of locators amongst the ones kept at the end of step 1. Overall, the methodology applied allowed to screen the whole field and its reservoirs, and to identify some promising pilot locations representative of the geology, for a given dynamic status, combining high level of knowledge and low risks related to CO2 injection.
Enhanced Dynamic Simulation through Continuous Fracture Modelling of Carbonate Reservoir, Oman
Authors: Al-Harthy Arafa , Al-Sinani Ibrahim , Al-Raisi Muatasam , Al-Azri Saud
Published: November 2012

This paper describes a workflow that was applied to a carbonate field in Oman to derive fracture and effective permeability models that were validated with multiple blind wells and reservoir simulation. The studied block is the largest and most faulted within a field which is currently under water-flood FDP. The study was kicked off with extensive borehole image interpretation. In parallel, several high resolution seismic inversions and spectral imaging attributes were generated as drivers to geological and fracture modelling. High resolution seismic was used to highlight subtle faults. Facies changes were also visible from seismic as seen in cored wells. Sequential geological modelling of GR, density, porosity and SW was carried out and constrained by seismic attributes.

The derived fracture frequency logs were compared against geological, structural and seismic drivers in a process called driver ranking. The results confirmed the role of faults as well as facies being primary controls of fracturing. Subsequently, the screened and cross-correlated potential drivers were carried forward to constrain the fracture models. Multiple stochastic realizations were derived through neural network training and testing and an average model was kept. Final models were validated against hidden BHI data. A new BHI was used to confirm model prediction. Different types of dynamic data in non-BHI wells were also used to validate the fracture models as specific production/injection related issues could be directly linked to presence of fractures. These data include PLT, PTA and tracer tests from which injectivity issues and short circuiting were explained by higher fracture densities and corridors derived from modeling.

Through dynamic calibration, the fracture model was converted to fracture permeability. The fracture permeability is the product of fracture density and a scaling factor derived from history matching. Subsequently, the addition of matrix permeability and fracture permeability will determine the effective permeability. This Keffective was directly used in the reservoir simulator without upscaling since it was part of the same grid hosting the fracture models. The results were encouraging as the simulation was smooth and error-free.
A New Temporary Chemical Packer Enables Efficient Stimulation of a Lower Zone in a HPHT Gas Well
Authors: Al-Ghazal Mohammed , Al-Driweesh Saad , Al-Sagr Abdulaziz , Krishnan Gopi , Jiménez José Camilo
Published: November 2012

As the oilfield industry requires new techniques to generate diversion over large pay zones and easier methods to perform workover operations and perform interventions through Coiled Tubing, research is focused to provide the industry with new technologies that support the growing demand for oil and gas in the world.

Fluid systems that are used to divert acid over large zones and generate non-mechanical isolation on a wellbore have traditionally been viscosified fluids and solid particulates. These substances create (in most cases) a drastic permeability reduction in the near wellbore area of producing zones that are meant to be protected. In operations that require divertion or the generation of a temporary plug, researchers have found that polymer based fluids are best suited, since they create less damage on the formation, and in the case of temporary plugs they can withstand higher differential pressures. The use of such fluids has reduced considerably the need for more complicated deployed techniques, such as mechanical packers, bridge plugs and mechanical diversion techniques.

This paper describes the first application of a polymer gel system in Saudi Arabian gas fields to isolate a section of a payzone on a vertical well, the system's design and operational challenges, and finally, its successful outcome and results. The objective of this application was to place a temporary plug between two producing zones to be able to selectively stimulate the lower zone.
Successful Implementation of Horizontal Multi-Stage Fracturing Enhanced Gas Production in Heterogeneous & Tight Gas-Condensate Reservoirs: Case Studies
Authors: Al-Anazi Hamoud A. , Abdulbaqi Dana M. , Habbtar Ali H. , Al-Kanaan Adnan A.
Published: November 2012

Heterogeneity and tightness of carbonate retrograde reservoirs are the main challenges to maintain gas well productivities. The degree of heterogeneity changes over the field and within well drainage areas where permeability decreases from few millidarcies to less than 0.2 md. Thorough studies have been conducted to exploit these tight reservoirs and not only focused on well performance, but have extended to assure enhancing and sustaining gas productivity through practical applications of technologies. The main objective of this paper is to assess the performance of Multi-Stage Fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectation. This paper gives a detailed analysis of well performances, exploitation approaches, and successful implementation and optimal cases to utilize new completion technologies such as horizontal multi stage fracturing to revive low producing gas wells due to reservoir tightness. Placing the horizontal wellbore reference to the stress directions plays a major role in the success and effectiveness of fracturing in enhancing and sustaining productivity.

Several wells have been drilled in tight reservoirs, but could not achieve or sustain the target gas rate. Recently, two wells were geometrically sidetracked targeting the development intervals based on logs of the original hole and completed with MSF toward the minimum stress direction. Open hole logs showed a low porosity development similar of the vertical holes. However, after conducting multiple stages fracturing, both wells produced a sustainable rate of more than 25 MMSCFD that prompted to connecting them to gas plants. Placing these sidetracks in the minimum stress direction helped to create transverse fractures that connect to sweet spots and sustain gas production. This paper provides thorough guidelines for selecting optimal candidates for MSF based on reservoir heterogeneity, proper design and execution of fracturing. It also addresses various components that contributed to the success of both wells, such as reservoir development, workover preplanning, geo-mechanics studies, drilling operations and real-time support, completion operations optimization and best-practices, and performance evaluation of other producers in the field. The paper also includes essential recommendations for development of tight gas reservoirs.
Multiphase and Wet Gas Flow Measurement - It's Not That Simple
Authors: Letton Chip , Hall Andrew
Published: November 2012

During the period since their inception around 1990 until today, multiphase flow meters (MPFMs) and wet gas flow meters (WGMs) have gone from a state of unreliable hardware and questionable answers, to a point where their reliability is becoming acceptable, while providing information that is essential for proper operation of oil and gas production systems.

Because the use of these devices is so much more common today than it was in the past, an illusion may exist in the minds of some that to select, operate, and maintain them at a satisfactory level of performance is straightforward - that they are "plug- and-play" instruments for the modern oilfield. While this remains a prime objective of meter development, it has yet to be achieved.

It is clear that multiphase and wet-gas flow meters have the potential to provide good answers over a broad range of conditions. However, achieving such performance requires more than just a cursory knowledge of upstream measurement. From selecting the right meter(s); in their commissioning, operation, and maintenance; and especially in the use of MPFM and WGM data, an in-depth understanding of many different aspects of the technology must be called upon. Will nature of the well production change significantly over the life of the field, for example moving from a liquid-dominant flow to one that is primarily gas? If the fluid properties of the production change with time, will the meter be capable of accounting for this, or will it require a sample for re-calibration, and is sample collection feasible? Will there be chemicals injected upstream of the meter that might cause confusion in the meter readings?

To adequately address these questions and account for changes in the system, users must track Key Performance Indicators (KPI) through the Life of the Field (LoF). This and other practical questions in the use of these important instruments are addressed and illustrated.
Advanced 3D Geomechanics in a North African Field
Authors: Kartobi Khelil , Ouriri Feriel , Lalili Wassila , Newman Robert , Grelaud Sylvain , Ismail Walid Ben
Published: November 2012

Hassi Messaoud in Algeria has been a major oil-producing field for more than 50 years, with many hundreds of wells successfully drilled. The complex geological structure and varying amounts of depletion mean that 3D geomechanical modeling techniques bring great benefit, particularly in predicting well-bore stability, sanding potential, and hydraulic fracturing. This paper describes such a model for one sector of the reservoir, creating 3D maps of mechanical properties and a 3D stress state that can be updated over time as pore pressures change. Several new methods of applying the results to well design are presented, including the creation of "mud weight cubes" and "sanding potential cubes" to assist with trajectory optimization and mud weight selection, and to provide limits on safe drawdown.
Effect of ‘Artificial Islands’ on Structural Integrity Management of Existing Offshore Platforms-Case Study
Authors: Varikkodan Abdul Gaffur
Published: November 2012

Four ‘artificial islands’ are being constructed in Giant Offshore Field in Abu Dhabi, for the purpose of using as centers for drilling and oil production. ZADCO carried out extensive studies to assess the effect of these ‘artificial islands’ on the existing field facilities, such as offshore jacket platforms and pipelines, as these ‘islands’ would permanently alter the estuaries / topographies of the offshore fields. Studies clearly established that these ‘alteration’ does influence the long term / short term hydrodynamic forces on the existing offshore facilities thus affecting ZADCO's structural integrity management plan. Therefore, it was important to quantify the extent of these changes on the existing jacket platforms such that appropriate modification to the current plan can be implemented. The present case study attempts to address the above issue by analyzing two representative jacket platforms, out of numerous platforms. SACS structural analysis software has been utilized for the analysis of these two platforms using hydrodynamic models developed for the two cases: (1) before the construction of artificial islands and (2) after the construction of ‘artificial islands’. Inplace, Fatigue and Pushover cases are part of major parameters used for the structural integrity of the offshore jacket platforms and the results of these analyses are part of critical input to the structural integrity management plans. It was observed that there were significant changes to the result of these analyses due to the introduction of artificial islands especially for the platforms which are having marginal reserve strength. This, in effect, alters current plan of inspection for critical nodes and members which need to be regularly inspected / monitored. It is also observed that the platforms pile on the mudline need to be inspected more frequently to know whether there are any changes to scouring of piles in soil. As a result of this case study it was established that such studies need to be performed while planning ‘artificial islands’ like facilities in offshore field like areas in order to asses its effect on existing facilities.
A Case Study of Modeling Workflow and Well Performance Assessment of a Complex Fluid / Tight Reservoir
Authors: Clara Cedric , Sherief Mohamed , Boalot Ahmed Tawfiq , El-Abd Salem Salem
Published: November 2012

Development of tight reservoirs with complex fluid behavior requires proper rock / fluid description and robust history match to understand and more accurately predict reservoir performance. This paper deals with reservoir modelling work undertaken for the evaluation of a tight reservoir, onshore Abu Dhabi.

The workflow for the construction of the static model with low permeabilities and strong heterogeneities is first discussed. The paper then presents a detailed analysis of reservoir surveillance data collected to assess the dynamic performance of a first well pair (producer / injector) drilled in the tight reservoir. Surveillance data include long term production / injection tests with multi PBU / PFO, interference testing and PLT data. A critical analysis of available data was performed in order to properly constrain the reservoir model. A PVT data review was also undertaken to build a robust Equation-of-State model.

A multi scenario history matching was performed with a compositional reservoir model and highlighted the importance of both permeability mapping and PVT modelling to match the complex dynamic well behavior. In particular, it was found that strong vertical compositional gradients prevail and can significantly impact well performance depending on structural elevation. This exercise showed the importance of analyzing data and understanding prevailing mechanisms driving well performance to properly constrain reservoir simulation model.

Because of limited available data at this stage of the development, significant uncertainties still exist. Hence the paper also presents key results from the uncertainty analysis and the data acquisition strategy designed to narrow identified uncertainties in order to optimize the development plan. Preliminary results from recent data acquisition campaign are also summarized.
An Interference Test Coupled with a Drawdown Analysis of Horizontal Well using a Multi-phase Flow Meter to Evaluate Reservoir Parameters and Connectivity
Authors: Al-Farhan Farhan , Gazi Naz , Al-Humoud Jamal , Tirkey Naween , Haryono Rafiq
Published: November 2012

Interference testing, although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of confirming communication and evaluating reservoir properties between wells. Similarly, a pressure build-up is one of the most accurate ways of estimating dynamic reservoir parameters surrounding the well, providing that the shut-in of the well is allowable. On the other hand, a drawdown test is not usually recommended due to the instability of the flow rate, and hence, the uncertainty in the parameter estimation when analyzing the transient of the pressure drawdown. In this project, due to production constraints a drawdown test was run for the active horizontal well as a substitute to the pressure build-up. It was therefore decided to couple the drawdown test with an interference test so as highlight the subsurface uncertainties. In order to achieve these objectives, careful design and operational coordination between the different asset teams and contractors is crucial to obtain interpretable and useful data.

Water production was observed in some of the nearby wells, and therefore communication between the horizontal well and the surrounding wells needed to be verified. The main objective of this project was to evaluate the reservoir parameters and connectivity surrounding the important horizontal well. In this test, the horizontal well was the active well in a five well interference test. The results of the test indicated different pressure behaviors seen from the observation wells corresponding to the pulse created by the horizontal well. Communication was established in some of the wells, whereas, faults were also verified in the surrounding regions. In addition, the drawdown analysis of the horizontal well showed all the flow regimes that relate to a horizontal wells’ signature as well as boundary behavior which coincide with the interference test results. The results of the drawdown analysis indicate the possibility and accuracy of conducting a pressure transient analysis using this method without being constrained with production objectives, and hence not shutting the well in.
Innovative Noise and High-Precision Temperature Logging Tool for Diagnosing Complex Well Problems
Authors: Ghalem Salim , Draoui Elyes , Mohamed Ayman , Keshta Osama , Serry Amr Mohamed , Al-Felasi Ali , Berrim Ahmed , Abu Chaker Hicham , Filenev Maxim , Gabdrakhmanova Alfiya , Aslanyan Irina , Aslanyan Arthur
Published: November 2012

Abu Dhabi's mature field with more than 50 years of production history and over 350 wells that is presented in this paper is one of the world's largest offshore oil fields. As oil fields mature, water and gas breakthroughs become increasingly frequent and the understanding of fluid movement becomes crucial for proper reservoir management, efficient remedial works and optimum workovers and future wells drilling, which all expected to enhance oil recovery.

This paper introduces an innovative logging technique designed to track fluid movement deep in the formation in flow and no-flow intervals and through casing.
3D OBC Seismic Survey Design Offshore Abu Dhabi - with Focal Beam Approach
Authors: Ishiyama Tomohide , Blacquiere Gerrit
Published: November 2012

We introduce a 3D ocean bottom cable (OBC) seismic survey design flow with the so-called focal beam method for finding the optimum acquisition geometry to satisfy geophysical requirements. This method is based on the so-called common focus point (CFP) technology, and it is a subsurface oriented and target oriented approach, making it possible to quantitatively analyze sought-after attributes, such as potential resolution and pre-stack amplitude fidelity, for one or more gridpoints in the subsurface of a given acquisition geometry.

We implemented the survey design flow offshore Abu Dhabi with several acquisition geometries to understand the effects of essential survey parameters, like 4D spatial sampling intervals with and without symmetric sampling, aspect ratio, roll pattern and wave type to be recorded, on the sought-after attributes. Summarizing these results, the relationship between essential survey parameters and resulting data quality was well understood.
Combination of Properly Engineered Reservoir Drilling Fluid and Filtercake Breaker Improves Performance of Extended Reach Wells Offshore Abu Dhabi
Authors: Saleh Medhat G. , Hassan Mahmoud M. , Medjiah Abdul Kader , Foxenberg William , Conn Tatiana , D'Mello Allwyn
Published: November 2012

This paper describes a combination of reservoir drilling fluid (RDF) and filter-cake breaker technology applied on four extended reach wells offshore Abu Dhabi which and provided multiple improvements in production rates of long horizontal laterals. The need for clean-up acid stimulations was reduced or eliminated in wells that could be beyond the reach of coil tubing.

The paper highlights the field implementation of these fluid systems and details the laboratory developmental work that coincided with the drilling and completion campaign. Three wells have been drilled with specialized reservoir drilling fluids (RDF) that included a premium grade xanthan, modified starch, carbonate with an internal filter cake breaker. Premium lubricants were included in the RDF to ensure that the drilling BHA could reach the ± 20,000 ft target depth and the liners could be run all the way to bottom. Acid stimulation of the nearly 10,000 ft reservoir sections was planned. The first two wells were drilled successfully, liners were run to bottom and the internal breaker was activated by a slightly acidic pH. The acid stimulation has only been performed on them to improve the initial production rate which was already near the expected target rate, while acid stimulation was not required for the third well as its performance has met the expected production rates. Subsequently, the fourth well utilized a more comprehensive cake breaker system and improved lubricant. Results of this well met production expectations also without the need for acid stimulation. Details of each well performance, field operations and results, including the laboratory development program are thoroughly discussed. Furthermore, impact of lubricants on RDF rheological properties, drilling performance and liner running torque and drag is detailed. In addition, the influence of reservoir drilling fluid design, lubricants and delay additives on the performance of the breaker is identified.
An Integrated Approach to Build 3D Fracture Model
Authors: Bellah Samir , Al Hosany Khalid J. , Najia Walid K. , Al Massabi Abdurrahman M.
Published: November 2012

An offshore Abu Dhabi carbonate oil field which was discovered in 1969 and put on production in 1985. The field produces from a reefal limestone formation deposited in the middle cretaceous. The field is characterized by good reservoir properties in the rudest banks well developed in the northern part of the field. Soon after production starts, wells water cut gradually increased to reach 50% within 4-5 years with drastic decline in oil production. Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases.

Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/ channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for, controlling water production problems and hence improving reservoir performance. In this contest, the operating company decided in 2006 to acquire 3D seismic to improve the field imaging and embarked in intensive well data gathering program including, FMI, coring, VSP and PLT measurements to improves the knowledge about the reservoir.

This paper will illustrate an integrated approach to build a 3D fracture model of Reservoir-A using a comprehensive full set of geological drivers obtained from seismic attributes, core and logs data which may control and explain the fracture occurrence in the reservoir. The model was used to enhance the history match accuracy and help also to assess new potential ideas for future development.
Low Salinity Enhanced Oil Recovery - Laboratory to Day One Field Implementation - LoSal EOR into the Clair Ridge Project
Authors: Robbana Enis , Buikema Todd , Mair Chris , Williams Dale , Mercer Dave , Webb Kevin , Hewson Aubrey , Reddick Chris
Published: November 2012

Clair Ridge will include the first offshore deployment of BP's reduced salinity LoSal® enhanced oil recovery (EOR) water injection technology. Over the last ten-years, there has been significant growth in the evidence supporting the use of low salinity water injection as a viable EOR process. BP, by using its LoSal EOR technology, has shown that incremental increases in oil recovery can be achieved across length scales associated with core flood experiments (inches), field-based single well chemical tracer tests (feet) and field trials (inter-well distances). This paper discusses the process undertaken by the Clair Ridge project in getting LoSal EOR adopted as a day one, secondary waterflood.

Confirmation and quantification of the LoSal EOR potential at Clair Ridge began in 2006 with completion of a series of core floods using three reservoir rock types. However, it was recognised that as a green field development single well chemical tracer tests or field trials were not possible ahead of sanction. Therefore, confidence in the materiality of recoverable oil by using LoSal EOR was built through integration of core flood data into reservoir simulation studies focused on a thorough investigation of the subsurface, produced water disposal and reverse osmosis operability uncertainties. In parallel, scoping facilities studies were completed to provide cost, weight and footprint estimates for inclusion of a 145 mbd RO plant on the platform. Finally, and critical to the success of this project was early and open partner engagement in LoSal EOR evaluation.
Theoretical Bases of Arps Empirical Decline Curves
Authors: Ling Kegang , He Jun
Published: November 2012

The famous Arps empirical decline curves provide a powerful and practical tool for production forecast. Numerous historical production data proved that Arps decline curves can be applied universally. With that many engineers use Arps decline curve without knowing reservoir properties and operating conditions. The lack in reservoir properties and operating conditions affects the quality of production forecast. Even with the knowledge of reservoir properties and operating conditions a reliable production forecast still cannot be guaranteed if we do not understand the theory that connects reservoir properties and operating conditions to production decline. The demand for a solid theoretical basis for production decline curve analysis trigged this study.

In this investigation, we derived the governing equations of production decline for different reservoirs by combining static geological and reservoir data with dynamic production data. With these equations the Arps decline curves are reproduced for different reservoir fluids and drive mechanisms. These equations indicate that Arps decline curves not only are empirical but also have theoretical bases. Engineers can use our governing equations to forecast production confidently.
Oil Production Optimization for Fields with Sensitive Wells and Gas Handling Limitation
Authors: R Pillai Ganeshram
Published: November 2012

Description

Oil industries with higher potential reservoirs are having restrictions to maximize the oil production when the gas handling capacities are limited with considerations to environment. There can be other limitations such as water handling capacity and well-head sensitivity limitations. To overcome these limitations this paper provides a comprehensive method, which was developed with combination of mathematical tools like curve fitting techniques to build well model from production test results and linear/ nonlinear programming for optimizing the well models.

Application

This method summarized can be applied to optimize/ maximize oil production in matured fields, fields with limitation on gas handling and high GOR limitations. Principle used in this paper can be used in fields with water handling limitation also. This will help reducing impact on environment as well.

Results and Conclusions

Results for maximum oil which can be produced with the gas plant design conditions, limitations are provided in this paper and set of well choke opening for the optimum production are generated by program for different cases. Previous works used the approach to optimize mainly gas lift wells, this paper proposes for oil production optimization, moreover previous works created well performance curves on the basis of oil production or estimations, but this work is based on choke opening and well test results of encoded wells.

Technical Contributions

A novel method of combining well test data to interpolate oil, gas, water production equation (Well performance curves) in terms of well choke opening (which is decision variable) is used. This paper provides optimum oil produced from field, Maximum oil which can be produced from field with different Gas limitations, and field maximum oil production capacity. All the above results are generated without using any specialized software.
Concept-Based Geologic Modeling Using Function Form Representation
Authors: Gai Xiuli , Wu Xiao-Hui , Varban Bogdan , Sementelli Kathryn , Robertson Gregory
Published: November 2012

Industrial standard technologies for detecting subsurface structures and rock properties either have limited resolution (e.g., seismic imaging) or limited coverage (e.g., well logging). It is usually necessary for a geologic model to incorporate interpreted or conceptual geologic descriptions that may have a significant effect on the movement of fluids in the reservoir. The conceptual descriptions or geologic concepts are often uncertain. In practice, it is important to conduct uncertainty analysis of different geologic scenarios, which involves multiple reservoir simulations on different geologic models with varying conceptual descriptions. Furthermore, when production history is available, it is important to adjust geologic models such that predictions based on these models match the production history. In either case, many reservoir simulations are usually required. Thus, precise and efficient modeling of geologic concepts while honoring measured data is critical to the successful application of geologic modeling.

In this paper, we present a function-form geologic modeling technique that allows for rapid construction and updating of geologic models with descriptive geologic concepts. Pre-built and re-usable concept models are used, which include elements and properties that may affect the flow response in the reservoir model. A concept model encapsulates rules and parameters that control the creation of geologic models based on a geologic concept. Explicit and implicit functional representations of geometry and 2D/3D property distribution are used to define concept models. Functions are parameterized and can be adjusted to honor measured data and to generate different realizations of concept models. Examples of using the function-form modeling technique will be presented for deep-water channelized systems.
Concentric Coil Tubing Helps Solve Challenging Acid Flow Back in High H2S Content Well
Authors: Ababou M. , Al Mujaini R. , Quesada C. Velazco , Taha W. Afify
Published: November 2012

Recovering acid after a stimulation job can prove to be very challenging in sandstone reservoirs, especially if the well has a potential to produce H2S. When the customer's gathering station is unequipped to handle acid or water, then it becomes impossible to flow the acid via the flow lines. The acid must be disposed at the surface in a separate facility as fast as possible. Allowing the acid to remain downhole for long time carries the risk of damaging the sandstone reservoir due to secondary precipitations. The customer, as per standard operating policy, does not allow flowing back fluids into their pits. Only return tanks are allowed, adding to the difficulty of flowing back stimulation fluids.

With the help of concentric coiled tubing, an innovative technique to produce back acid from H2S wells became the sole solution to a major flowback challenge in South Oman wells. The technology successfully enabled the recovery of stimulation acid from a customer's well that had high H2S content, without producing any H2S at surface. The unique approach consisted of mixing an H2S scavenger with a scale inhibitor. This mixture was used as the power fluid for the concentric coiled tubing tool. With the help of the good shearing energy at the WellVac BHA, combined with the small concentric coiled tubing return annulus, the H2S scavenger solution was perfectly mixed downhole with the return fluids, and no H2S was produced or recorded at the surface return tanks. This new technique will certainly open new possibilities to stimulate many more wells that could not be stimulated previously due to high H2S content. The technique would also eliminate the great costs of a portable flare system.
Ion Chromatography Analysis of Advanced Ion Management Carbonate Coreflood Experiments
Authors: Vo Loan T. , Gupta Robin , Hehmeyer Owen J.
Published: November 2012

Advanced Ion Management (AIM) is an enhanced oil recovery (EOR) process where waterflood injection water is modified by the addition, removal, or dilution of ions. AIM can yield an increase in oil recovery compared to waterflooding using formation brines. To better understand the oil recovery mechanism of AIM in carbonates, ion chromatography studies and salt solubility measurements were conducted on AIM brines used in floods of Middle Eastern core.

The ion composition of the brines – upon mixing after extended time, at reservoir temperature and pressure, and after core flooding - were compared to elucidate the ion composition changes during an AIM waterflood and how those changes could lead to additional oil recovery. That knowledge could potentially be used to screen reservoir rock types and available water sources to determine which would be best suited for EOR from AIM waterflooding.

AIM technology encompasses a wide range of injection brines, and thus this ion chromatography analysis covers a range of modified brines, including brines for which analyses have not been previously published. Analysis of the results has implications for how ion composition may be correlated with oil recovery and what facilities are required to obtain the desired composition. The study finds that neither rock dissolution nor ion exchange alone is sufficient to explain oil recovery with modified brine injection, and neither mechanism is a guarantee of additional oil recovery. It also finds that sodium phosphate, borax, and sodium sulfate all precipitate divalent cations from seawater at field operating conditions.
Experimental and Theoretical Investigation of Water/Gas Relative Permeability Hysteresis: Applicable to Water Alternating Gas (WAG) Injection and Gas Storage Processes
Authors: Fatemi S. Mobeen , Sohrabi Mehran
Published: November 2012

Accurate determination of relative permeability hysteresis is needed for reliable prediction of WAG injection. We report two series of gas/water kr hysteresis curves obtained from corefloods under mixed-wet conditions. The first set began by water injection (imbibition: I) in the core saturated with hydrocarbon gas and immobile water. Then, the injection of gas (Drainage: D) and water continued sequentially and in total, three imbibitions and two drainages were carried out (IDIDI). In the second series, the core was initially 100% saturated with water and the experiment started with drainage (gas injection) followed by successive imbibitions (water) and drainages (DIDIDI) periods. The measured pressure drop and production data were history matched to obtain krg and krw values for each imbibition and drainage. The results show cycle-dependent hysteresis for both krg and krw curves. Therefore, the current assumption in existing hysteresis models that the drainage scanning curves follow the preceding imbibition curve is not supported by our experiments. Historic behaviour of both krg and krw is qualitatively different for these two series of experiments. This shows that unlike water-wet systems, relative permeability historic behaviour in mixed-wet system can be a function of injection scenario (saturation history). In the IDIDI series, both krg and krw decreased as the alternation between imbibition and drainage injection continued. In the DIDID series, no significant hysteresis was observed for krw, but krg in drainage cycles were higher than the corresponding values in preceding imbibition cycles. The results reveal that, none of the widely used hysteresis models (e.g., Carlson, Killough) is able to predict the observed cyclic kr hysteresis for alternating injection of gas and water. The results suggest that for mixed-wet systems it is necessary to consider irreversible hysteresis loops for both the wetting and nonwetting phases. In addition to WAG injection, the results presented in this paper and the conclusions drawn also have applications in underground hydrocarbon gas storage which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on annual basis.
Design & Implementation of CO2 Huff-n-Puff Operation in a Vietnam Offshore Field
Authors: The Ha Giang , Dinh Tran Ngoc , Vu Huy Huu , Takagi Sunao , Mitsuishi Hiroshi , Hatakeyama Atsushi , Uchiyama Tadao , Ueda Yoshiaki , Van Nguyen Toan , Phan Trung Ngoc , Nguyen Hoan Ngoc , Nguyen Trung Huu , Dinh Quan Manh
Published: November 2012

The Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) application to the offshore oil field in Vietnam has been investigated through an international joint study scheme between Japan and Vietnam since 2007 and a preliminary study for potential CO2 EOR application indicated feasibility to some extent. To reduce and mitigate technical uncertainties/risks in the field scale EOR implementation, in May 2011, a CO2 EOR pilot test was executed in a sandstone reservoir of Rang Dong oil field, offshore Vietnam.

The test was designed to be conducted as a single-well test, and generally called CO2 Huff-n-Puff. Major field operations included test string installation, pre-CO2 injection flow, CO2 injection (ca. 111 metric tonnes) and post-CO2 injection flow. Whole operation was performed satisfactorily with all objectives achieved. During the test, clear increment of oil rate and reduction of water cut were observed after CO2 injection as well as oil composition change. The contrast of CO2 injectivity and oil saturation change in the reservoir was confirmed by saturation logs, etc.

Being the first CO2 EOR application in Southeast Asia and also offshore application worldwide is rarely reported, the operational gained is especially valuable. This paper is to describe the process of engineering design, planning, onshore preparation and field execution leading to the success of the project1.
Identification of Top Bitumen Surface in an Upper Jurassic Carbonate Reservoir Using a Seismic AI Inversion with Geostatistical Technique
Authors: Inoue Hiroyuki , Kojima Haruo , Al Shehhi Jamila , Mahgoub Mohamed Ibrahim , Suleiman Ayman , Fahmy Ismail , Shibasaki Toshiaki , Al Ameri Mohamed Braik
Published: November 2012

"A field" located in offshore Abu Dhabi has produced oil from the Upper Jurassic carbonate reservoirs for 25 years. The one of the main characteristic of this reservoir is an existence of bitumen (tar mat) zone intersecting sub-layers in the reservoir and porosity deterioration is observed in the bitumen zone and below bitumen zone. Since porosity deteriorates sharply from 20% to less than 5% at top of the bitumen, it is crucial to represent the bitumen surface in order to estimate hydrocarbon reserves and optimize future infill well locations

In order to characterize the reservoir properties and identify the bitumen surface, an ocean bottom cable (OBC) 3D seismic data was acquired over A field in 2010. Seismic processing results was confirmed as a high quality data to proceed reservoir characterization studies by seismic to well tie, amplitude fidelity and low frequency level during structural interpretation work. However one of the main challenges to achieve the objective is seismic resolution because the porous interval above bitumen zone is thinning toward the flank area. Therefore seismic acoustic impedance (AI) inversion with a geostatistical approach was selected to overcome this challenge.

This geostatistical AI inversion was performed by (1) log data editing and rock property analysis (2) well to seismic tie and wavelet extraction (3) low frequency model building (4) deterministic AI inversion (5) geological model framework building, and (6) stochastic AI inversion, with investigations of these uncertainties. For stochastic AI inversion stage, 50 number of multi-realizations of AI and porosity volumes were generated in order to define the top bitumen surface. Based on these realizations, several combinations of porosity and probability cut-off values were generated to identify the probabilistic top bitumen surface as well as high reservoir quality area. These results can be used as a guide to build a 3D geological model and define well planning.
Polyolefin Materials for Large Diameter Cooling Systems
Authors: Harjuntausta Jarmo , Murali Mohana
Published: November 2012

Polyolefins have a long and successful track record as a material for low pressure piping applications in Europe. For example, drainage systems made from Polypropylene Block Copolymers (PP-B) have now been in service for over 30 years and since the introduction of the new PP high Modulus (PP-HM) grades in the 1990's, market growth has been remarkably high. This market growth was further supported by the emergence of technology that allows for the production of large diameter PE/PP pipelines of up to 4 m in diameter.

Against this background, the polyolefin pipe market in Asia and Middle East is now set for a similar strong growth to that witnessed in Europe. With the continued failure of systems made from alternative materials such as concrete, there is a significant opportunity for polyolefin pipes to replace existing networks. This paper will underline the whole life value of polyolefin pipes compared to other systems, highlight the potential for large diameter plastic pipes and underline the growth and subsequent opportunities for plastic pipes in the Middle East, particularly in the petroleum industry.
Deploying Wireless Technology for Process Plants to improve Safety, Reliability and Efficiency
Authors: Qureshi Feroz
Published: November 2012

Industrial wireless has found acceptance in all types of process industry plants. Apart from reducing costs associated with wiring, installation, commissioning and operations, wireless is an enabling technology that can minimize risks and the likelihood of harmful incidents at a marginal cost to end users.

The following paper describes the latest advancements in industrial wireless, and explains how wireless solutions can be used to address Health, Safety and Environment (HSE) challenges in a typical processing operation.