bluuebunny/crossref_metadata_2025 huggingface dataset:
An Approach to Fracture Characterization Using Borehole Seismic Data
Authors: Dutta Pradyumna , Singh Sunil Kumar , Al-Genai Jarrah , Akhtar Azhar , Akbar Mahmood
Published: June 2009

The Najmah, Sargelu, and Marrat reservoirs are the main Jurassic reservoirs in Kuwait. These fractured-carbonate reservoirs that have moderate-to-low porosity were deposited in an inner- to midramp warm marine environment. The fracture systems play a significant role in production in these reservoirs, and it is essential to identify areas of high fracture density. It has been observed that fractures associated with certain faults have facilitated the flow in the Jurassic reservoirs. Identification of faults and associated fractures mainly has been on the basis of 3D-/2D-seismic data, image logs, cores, and thin sections.

The Greater Burgan field consists of the Burgan, Magwa, and Ahmadi structures. The four main reservoir units in the Greater Burgan field are the Wara, Mauddud, Burgan Third, and Burgan Fourth sands. The deeper reservoirs—namely, the Lower Cretaceous Ratawi and Minagish limestone—and the Jurassic Marrat formation contain significant oil reserves but are of less importance. However, a recent successful exploratory well in the Arifjan prospect, which is located on the eastern flank of the Greater Burgan field, has opened up a large area that was previously considered to be nonproductive. It has been noticed that there is excellent correlation between the fractures observed in cores and image logs and those predicted from the converted component of the zero-offset vertical seismic profile (VSP). After registration of the z-component image with the converted image for various prominent reflectors, the discontinuities in the reflectors in the converted-component image revealed fracture swarms that could be traced away from the wellbore.

This technique of processing the VSP data to identify fracture clusters could form a bridge between surface and borehole data and improve confidence in predicting fracture swarms away from the wellbore and also assist in planning of future surface seismic and 3D VSP surveys.
Evaluating Crystallization Risks in Liquefied-Natural-Gas (LNG) Production
Authors: Luis F. Ayala H. , Juan Emilio Fernández L.
Published: June 2009

Liquefied natural gas (LNG) is anticipated to dominate world energy trade and fill the gap between production and energy demands in a few years, especially in the US. LNG is the liquefied version of dry natural gases at ultralow temperatures (approximately −160°C or −260°F at atmospheric pressure), which aims at minimizing storage volume requirements needed for overseas transportation. Within this context, it is clear that technology must continue to be developed to optimize the thermodynamic processes involved in the compression, liquefaction, and revaporization of LNG and associated operational challenges. One key challenge during the production of LNG is the presence of trace amounts of heavy components in the gas feed composition is known to induce the precipitation of a solid phase during the cooling process, which presents the risk of equipment plugging and associated hazards. However, there are very few general thermodynamic tools available for the prediction of solid-liquid equilibrium for very low-temperature conditions (<−200°F). In this study, available thermodynamic predictive tools are evaluated for the determination of LNG crystallization conditions. Previously presented crystallization prediction models are examined, and potential pitfalls identified. The results from this study are expected to provide a better understanding of the thermodynamics of LNG processes and provide a framework for subsequent work in the analysis of LNG refrigeration and liquefaction processes—typically considered the key elements of any LNG project.
Eliminating Buoyant Migration of Sequestered CO2 Through Surface Dissolution: Implementation Costs and Technical Challenges
Authors: Burton McMillan , Bryant Steven L.
Published: June 2009

Sequestration of carbon dioxide (CO2) in geologic formations will be part of any substantive campaign to mitigate greenhouse gas emissions. The risk of leakage from the target formation must be weighed against economic feasibilities for this technology to gain stakeholder acceptance. The standard approach to large-scale geologic sequestration into saline aquifers assumes that CO2 will be injected as a bulk phase. In this case, the primary driver for leakage is the buoyancy of CO2 under typical deep-reservoir conditions (depths > 2,600 ft or 800 m). Investigating alternative approaches that use inherently safe trapping mechanisms can help to characterize the price of reducing the risk of leakage.

In this paper, we examine a process in which CO2 is dissolved in brine before injection into deep subsurface formations. The CO2-laden brine is slightly denser than brine containing no CO2, so the complete dissolution of all CO2 into brine at the surface before injection will eliminate the risk of buoyancy-driven leakage. The process considered here involves dissolving CO2 at surface facilities. We determine the capital costs for the additional facilities and compare them the capital costs for injecting bulk-phase CO2. We also estimate the power requirements to determine the additional operating costs. The additional capital and operating costs can be regarded as the price of this form of risk reduction.

Comparing this alternative to the standard, we find that an additional power consumption of 3 to 9% of the power plant capacity will be required, and the capital costs will increase by approximately 60%. Brine is required at rates of millions of barrels per day and would be lifted from the target aquifer. The bulk volume of the aquifer is on the order of a hundred million acre-ft for reasonable power plant sizes (250 to 1,000 MW) and for reasonable injection periods (30 to 50 years). Although this alternative results in higher costs, surface dissolution may be attractive when the costs of monitoring or ensuring against buoyancy-driven CO2 leakage exceed these additional costs.
Retention of CO2-Foaming Agents on Chalk: Effects of Surfactant Structure, Temperature, and Residual-Oil Saturation
Authors: Fjelde Ingebret , Zuta John , Hauge Ingrid
Published: June 2009

Injection of carbon dioxide (CO2) is a well-known enhanced-oil-recovery (EOR) technique. Formation of stable foam inside the reservoir can improve macroscopic sweep efficiency. On the other hand, retention of surfactants decreases the cost-efficiency of the EOR process. This paper presents flow-through retention experiments with CO2-foaming agents on outcrop Liege chalk plugs at two different temperatures: 55 and 70°C. Two branched ethoxylated (EO) sulfonates with different ethoxylation degree, S1 (EO = 7) and S2 (EO = 12), were used. The aim was to investigate the effect of ethoxylation degree on surfactant retention. Furthermore, the effects of temperature and residual oil on surfactant retention were studied. The effect of waterflooding followed by CO2 flooding on surfactant retention at reservoir conditions was also examined. Partitioning of the foaming agents between water and oil phases was studied.

Results show that increasing the ethoxylation degree of the surfactant decreases the retention on chalk cores saturated with formation water at 55°C. S2, which was found to give the lowest retention at 55°C, was found to have a higher retention at 70°C. The presence of residual-oil saturation after waterflooding (Sorw) decreased the retention of S1 and increased the retention of S2 in comparison to the absence of residual oil. The retention of S2 after waterflooding followed by CO2 flooding at 340 bar and 55°C was in the same range as retention on 100%-water-saturated core, but significantly lower than retention in residual-oil-saturated cores. The experiments have shown that not only are surfactant structure and temperature important for the retention of surfactants, but also the presence of oil.
Characterization of Oil/Water Flows in Inclined Pipes
Authors: Atmaca S. , Sarica C. , Zhang H.-Q. , Al-Sarkhi A. S.
Published: June 2009

Oil/water flow is a common occurrence during production and transportation of petroleum fluids through pipes. Understanding of oil/water pipe flow behaviors is crucial to many applications including design and operation of flow lines and wells, separation, and interpretation of production logs. In this study, the oil/water pipe flow was experimentally investigated for different inclination angles (0°, ±1°, ±2° and −5°). A total of 324 tests were conducted in a 0.0508-m (2-in.) ID 21.1-m (69.6-ft) long test section using tap water and mineral oil with superficial velocities ranging from 0.025 to 1.75 m/s. The experimental results include observations of flow patterns and phase distributions, and measurements of water holdups and pressure gradients. A high-speed video system was used to observe the mixing status between oil and water and to determine the flow patterns at various flow conditions. Quick closing valves were used to measure the phase holdups and to demonstrate the slippage between oil and water with the water cut to water holdup ratio. The experimental results of flow pattern transitions, water holdups, and pressure gradients are compared against predictions of the Zhang and Sarica (2006) model. The model performance is analyzed based on the experimental observations and the modeling considerations. Recommendations are presented for future model improvement.
Identifying Layer Permeabilities and Skin Using a Multi-Layer Transient Testing Approach in a Complex Reservoir Environment
Authors: Eissa Moustafa , Joshi Sameer , Singh Kamaljeet , Bahuguna Ajay , Elbadri Mohamed
Published: June 2009

Conventional pressure transient testing, using a pressure gauge positioned at a fixed depth in a well, has historically been the main source of permeability and skin estimation in formations. However, if a well is completed as a multi-layer commingled producer, then this conventional approach makes it difficult to measure the permeability and skin of individual layers.

Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia, Bentiu-2 and Bentiu-3 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. A selective inflow performance (SIP) test was carried out during production logging (PL) jobs in some of these wells and it indicated that the productivity index (P.I.) of the individual layers varies widely, ranging from 1.5 to 15 b/d/psi. This illustrated the need for a method to estimate the permeability and skin of each layer. This information was needed for reservoir model calibration, well productivity prediction, low productivity diagnosis and remedial action selection.

Two solutions were proposed to GNPOC; use the conventional technique of isolating each layer and testing it separately or carry out a commingled multi-layer transient (MLT) test with a PL tool. In an MLT test, in addition to the normal PL runs, individual pressure transient stations are also recorded at the top of each contributing layer. The MLT test measures the flow rate and wellbore pressure above each producing layer for different surface flow rates during the infinite-acting phase. These individual layer flow rates and pressure transients are used to calculate the individual layer properties.

GNPOC decided to go in for the MLT testing option and two wells were analyzed. In the first well, MLT testing showed that one of the layers had a very high permeability compared to the other layers. It depleted much faster and had early water breakthrough. Consequently a water shut-off job is planned for this layer. In the second well, MLT analysis showed that the upper layer had poorer permeability as compared to the lower layers. However, this layer holds good oil reserves. Hence, this well is a good candidate for future side tracking into the upper layer, in order to exploit the untapped reserves in this layer.

In this paper, we will discuss the MLT testing technique, introduce a workflow for the analysis, and then will discuss the results of the analyses for two examples from GNPOC. Based on the success of these cases, multi-layer transient testing is estabilished as a preferred testing technique in this complex reservoir environment.
The Total Control of Well Integrity Management
Authors: Smith L. , Milanovic D.
Published: June 2009

This paper describes a web-based program which provides a comprehensive approach to well integrity management covering all potential integrity threats to the whole well. This "cradle-to-grave" software, the Intetech Well Integrity Toolkit (iWIT), provides well information and data analysis for timely, informed, decision-making. Using its own or existing client databases, this software carries out quantitative data analysis in real-time and provides feedback to the operator about the condition of individual wells and also overviews of the whole field integrity status.

The iWIT software has been used in fields with less than 50 up to over 1600 wells. Installations have been made in primary recovery fields to tertiary recovery fields, both onshore and offshore. The software has been installed in new and mature fields; some fields with no automation in place and some which have been automated for over a decade.

All the operators that have installed the software to date have decided to expand its use, either to incorporate more assets (e.g. the integrity management of the flowlines up to the manifold) and/or to install the system throughout their group operations internationally. Current installations include two Gulf operators in Abu Dhabi and Qatar.

The management of well integrity is a vital element in the successful, economic and safe operation of all assets. Data relevant to well integrity is widespread, including the safety critical elements test results; monitoring of annulus pressures; evaluation of tubing and casing integrity; inspection results from well logs; evaluation of scaling risks etc. The management of, and continuous evaluation of, this vast range of data presents a huge challenge. The system described in this paper has met that challenge comprehensively.
A Laboratory Investigation of Water Abatement Chemicals for Potential Use in the Wanaea Oil Field
Authors: Sidiq Hiwa H. , Amin Robert , Kennaird T.
Published: June 2009

The disadvantages of water influx into a producing well include reduced relative permeability to hydrocarbon and increased expenses for both water handling and corrosion control. An effective water control technique is, therefore, highly desirable. One potential solution for reducing excessive water production is the injection of "Relative permeability modifier" (RPM) chemicals into producing wells. The work described in this paper is concerned with finding a highly selective chemical to reduce water production without affecting oil production. Presented herein are results of laboratory tests using relative permeability modifiers in conjunction with core samples from the Wanaea field.

The oil producing Wanaea field is operated by Woodside Energy offshore Western Australian. Some of the wells suffer from high water cut, therefore the introduction of a relative permeability modifier (RPM) has been considered.

Four RPM chemicals were tested with core plugs taken from Unit II of well Wanaea-3 (core depth 2832.00 to 2844.50 m). Laboratory experiments were conducted on 4 reservoir core plugs, with air permeabilities ranging from 158 to 334 md and porosities from 16.4 to 19.9%. The objective of the tests was to assess the effectiveness of selected RPM's in selectively reducing water production.

The experimental results demonstrate that the chemicals were variably effective in reducing the relative permeability to the water phase, but they also variably affected the relative permeability to the oil phase.
Lean Duplex Materials for Line Pipe Applications in Sweet and Slightly Sour Environments
Authors: Rommerskirchen Iris , Lemken Sven , Hoffmann Reinhold , Butting H.
Published: June 2009

For some years, lower alloyed austenitic-ferritic stainless steel grades have been developed, which are summarised in the „lean duplex"- family of alloys. So far, lean duplex materials have been mainly used as plate material for construction of containers and vessels in the pulp and paper business as well as in architecture and construction.

As they are lower alloyed in nickel and molybdenum compared to standard duplex grades, lean duplex grades can offer economically interesting advantages combined with a higher degree of technical reliability compared to supermartensitic stainless steels.

Aim of the present study was to figure out, whether lean duplex grades can close the gap between supermartensitic steels and standard duplex stainless steels with regards to weldability, structural stability, mechanical properties as well as corrosion behaviour in typical media for the oil and gas industry.
Downhole Fluid Analysis Integrating Insitu Density and Viscosity Measurements - Field Test from an Oman Sandstone Formation
Authors: Khalil Mosleh , Rumhi Huda , Randrianavony Mahaly , Mullins Oliver C. , Godefroy Sophie
Published: June 2009

The new generation of wireline formation testing fluid analyzer presented in this paper integrates in-situ optical fluid analysis device with a oscillating mechanical sensor providing downhole density and viscosity measurements in real-time at reservoir conditions. Fluid density is measured primarily by measuring corresponding changes in the vibrational frequency of the oscillator while viscosity is determined primarily by monitoring the decay time of the resonance. The formation testing wireline tool was utilized in combination with the new optical fluid analyzer to identify the fluid types downhole in the complex lithology reservoir drilled with an oil based mud. Focused sampling was essential to reduce mud contamination thereby enabling accurate determination of fluid compositions and properties such as density and viscosity.

The in-situ optical fluid analyses provide the quantitative hydrocarbon compositions in terms of C1, C2, C3-C5, C6+, CO2 along with the water fraction in both oil based mud (OBM) and water based mud (WBM) wells. Gas Oil Ratio (GOR) or Condensate Gas Ratio (CGR) is also computed from the optical analyses. The density measurement provided by the mechanical sensor brings additional value in comparison with pressure gradient analyses and is critical to evaluating thin, tight or depleted flow units. The viscosity measurement, the first downhole measurement of its kind, is particularly important as viscosity is one of the key fluid properties that directly affect the producibility of the flow units.

A field test was conducted in an onshore reservoir in the Sultanate of Oman. It was performed in a well having oil, gas and water zones. As a result of the quantitative downhole compositional analyses and fluid property measurements, single phase samples with low mud filtrate contaminations were collected. The PVT laboratory results served as a valuable comparison for the fluid composition as well as density and viscosity measurements.
Solid Expandable Technology for Zonal Isolation of Loss Circulation Formation: Case Study Shuaiba Formation
Authors: Ekpe J. , Alexeenko A. , Al-Thuwaini J. , Emad M. , Khanlarov R.
Published: June 2009

The frontier exploration drilling campaign in the Kingdom of Saudi Arabia for LUKOIL Saudi Arabia Energy Ltd started in January 2006. LUKSAR, a joint venture between Lukoil & Saudi Aramco, took pragmatic approach to project management. A careful analysis of campaign challenges with proper planning to meet the drilling campaign targets. One major challenge was to stick to well program to ensure well targets are met and exploration objectives achieved. The reduction of wellbore diameter due to hole problems during well construction has always posed a great challenge to well completion. Having said that, there are few technologies at present that provide the capability to execute well intervention/work-over in slim hole wells and where there are available, they usually cost a fortune. The restriction created in reduced hole sizes typically results in a complicated drill stem testing program (DST), formation fracture pressure limitation, decrease in production rate due to restriction in tubing selection and high intervention cost. On Luksar Expl well #4, the above mention challenge was a reality. While drilling, encountered severe loss circulation in Shu'aiba carbonate formation compounded with sloughing shale problems in the shallower Wasia formation. As a result, it became difficult to drill further and set planned casing at bottom. Utilizing expandable tubular across loss circulation zone enabled Luksar to restore the original well casing design.
Evaluation of Miscible and Immiscible Gas Injection in One of the Iranian Fields
Authors: Delfani S. , Mortezapour A. , Firouz A. Q. , Shadizade S. R.
Published: June 2009

A compositional reservoir simulator has been used to determine the reservoir management and production strategies to optimize the oil recovery from an offshore low porosity, low permeability carbonate reservoir with permeability of 1–3 md and porosity of 5–20%. This reservoir is a candidate for an EOR process, because the reservoir production rate has been declined rapidly to about half of the initial production rate within four years. The injection techniques that were used in this study include gas injection with different fluid that it causes miscible and immiscible process. Specific strategy that was used includes the use of injectors and producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir is miscible gas injection. This production strategy has resulted in better efficiency and therefore higher oil recovery and good economics.
New Technique to Cure Losses in UeR Formation in South Oman Field—A Case Study
Authors: Mahapatra Shrikant K. , Stevenson Eddie , Al Fadhli Abduallah
Published: June 2009

As part of the field development plans for the South Oman oil field, four trial wells have been drilled to assess the impact of steam injection on productivity and recovery. At the outset of the trial, it had been determined that lost circulation was a major drilling problem in the UeR formation in this area. Lost circulation (LC) is a phenomenon wherein circulating drilling fluid is lost to fractures and pores in the rock formation rather than returning to the surface through the wellbore annulus. If not corrected beforehand, the lost circulation that occurs during the cement job can lead to incomplete sealing of the annulus, which may require remedial cementing to attempt to fill the annulus. Moreover, voids in the annular space are potentially disastrous, especially in steam injection wells, because of the expansion of the pipes when exposed to elevated temperature during the steam injection. Typical reported LC-based problems such as buckling of casing, bi-axial collapse, and wellhead growth are the results of poor cement coverage behind casing strings.

The normal practice is to stop the losses either with loss circulation material (LCM) pills or with cement plugs of a recipe different from that used to mix the original slurry. These methods were tried in the first well in this campaign; however, they did not give satisfactory results. As an alternative approach, an improved fluids train was programmed that would maximize the benefits of the cement slurries. This new technique was successfully applied and subsequently used in the next three wells in the campaign. The same technique was also used successfully in subsequent wells drilled in the field. As a result of the successful curing of losses, the production casing could then be cemented to surface. The successful curing of losses with the new technique has also led to rig-time savings, and bond logs also indicate good cement bonds.
Environmental Study for Two Gas Pipelines Through the Baltic Sea
Authors: Valeur Jens Rosendal , Larsen Joern Bo , Stroebaek Neel
Published: June 2009

Two gas pipelines connecting Russia and Germany through the Baltic Sea are planned to be constructed during the period 2010-2012. The pipeline system will enable an annual transportation of 55 billion cubic metres (bcm) of natural gas from Russia to the European gas grid.

Comprehensive studies of the potential environmental impacts of the project have been carried out. Special attention has been given to the fact that the Baltic Sea is a unique and vulnerable environment. It can be considered the world's largest estuary, with marine life adapted to the brackish water environment and with limited water exchange with the surrounding sea through the Danish straits.

Valuable experience from major bridge and tunnel construction works across the Danish straits during the 1990s has been used in order to carry out an assessment of the environmental impact of the gas pipeline project and in order to design the construction works in an environmentally friendly way.

The environmental aspects of the various phases of the pipeline project have been identified, and their environmental significance has been assessed. A rating system for classifying the environmental impacts has been developed. Classification has been carried out based on type of impact and extent in terms of space and time.

The environmental aspects of the project have been integral to the planning phase to ensure that the design of the pipeline system is environmentally optimised. A major task has been to identify the optimal route, taking into account both the important nature areas in the Baltic Sea and the special precautions related to the presence of dumped munitions in parts of the Baltic Sea. The environmental analyses show that the pipelines can be constructed, operated and decommissioned with no long-term impacts on the marine life of the Baltic Sea.
Seismic and High-Resolution Sequence Stratigraphy of the Upper Cretaceous Simsima Formation, Onshore Abu Dhabi Oil Field, United Arab Emirates
Authors: Hozayen M. A. , Strohmenger C. J. , Mueller K. , Al-Marzouqi S. H. , Shuaib M.
Published: June 2009

An important carbonate oil field, located onshore Abu Dhabi, has been producing from the Upper Cretaceous (Maastrichtian) Simsima Formation since 1983. To optimize and increase production of the field, seismic and high-resolution sequence stratigraphy was integrated by tying fourth-order, high-frequency sequences identified from core to 3-D seismic data.

To establish the sequence stratigraphic framework, a new detailed sedimentological and high-resolution sequence stratigraphy study had been carried out, integrating approximately 7,000 feet of core material, approximately 3,500 thin sections, and all available well-log data from 46 wells. Core description, together with semi-quantitative petrographic examination of thin sections, established a new depositional model for the Simsima Formation. Sixteen lithofacies types (LF1 to LF16) representing a wide variety of depositional environments, ranging from upper ramp, rudist-bioclastic shoals to open marine mid to outer ramp mud-dominated settings. The newly developed, high-resolution sequence stratigraphic framework suggested that the Simsima Formation comprises one complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. These third-order composite sequences include seventeen high-frequencies, fourth-order sequences (HFS). HFS-1 to HFS-12 build the older third-order composite sequence, HFS-13 to HFS-17 form the transgressive system tract of the overlying, younger third-order composite sequence. 3-D seismic cross-sections show that fourth-order high-frequency sequences HFS-1 to HFS-6 of the older third-order composite sequence clearly show onlap on a pre-existing high (pre-Simsima unconformity surface), whereas the top part of the Simsima Formation (high-frequency sequences HFS-13 to HFS-17) show various degree of erosion. The established high-resolution sequence stratigraphic framework provides the layering scheme for the next generation Simsima 3-D static model, which will be used as input for the reservoir flow (dynamic) model.
Reservoir Rock Typing from Crest to Flank is There a Link?
Authors: Basioni R. E. Mahmoud , Negahban R.E. C. Shahin , Dawood S. R. E. Ahmed , El Mahdi S.R. E. Ahmed , Bahamaish T. L. Jamal
Published: June 2009

Minimizing uncertainty associated with predicted log water saturation can be best achieved through the integration of log analysis (formation evaluation) and capillarity (core measured high pressure mercury and oil/water drainage capillary pressure data). Further reduction of uncertainty in predicted formation water saturation requires; first the most probable log porosity solution interpretation; second the most probable log porosity/permeability relationship (match core measured values); and third a quantitative capillary pressure model that represents measured high pressure mercury and oil/water drainage capillary pressure data.

This paper is a continuation of previous work done using the classical Leverett-J method (Leverett 1941) in integrating capillary pressure data with routine core analysis and petrophysical rock types to generate a robust model for predicting formation water saturation profiles. Two datasets were used in the application of this method in two phases. Phase 1 was accomplished by using the first dataset, which is for a crestal well, in characterizing reservoir rock types by the assignment of capillary pressure curves to their corresponding rock types. This process was accomplished by grouping rock types according to discrete ranges of the interval speed which is defined as the square root of core measured permeability divided by porosity (k/ϕ) data. Each range of the interval speed will have a corresponding Leverett J function from which water saturations will be interpolated according to its respective height above the Free Water Level (FWL) (using the log predicted permeability-porosity ratios). In phase 2, the second dataset, which is from a flank well, was used to quality check the rock typing interpretation and to aerially map the change in reservoir rock types when going from crest to flank. One of the main findings from this work is the importance of quantifying the cementation process that took place in rocks' post-deposition.

In the absence of clear fluid contact, a trial and error method was followed to adjust the FWL until a good agreement between the log predicted water saturation and the predicted water saturation from the capillary pressure correlation was reached. The error in averaging was minimized by increasing the number of rock types (minimizing the ranges of interval speed) using a large number of measured high pressure mercury and oil-water drainage capillary pressure data. Furthermore, this paper presents a comprehensive comparison of the log derived and model predicted water saturations.
Building a Deterministic 3D Model of Tar Mat deposits in a Carbonate Reservoir in a Geologically Consistent Manner: A Case Study from Offshore Abu Dhabi
Authors: Ruelland Philippe J. , Lehmann Christoph T. , Al Hosany Khalil I. , Cobb David O.
Published: June 2009

The presence of a Tar Mat in carbonate reservoirs in the Gulf region is common. Tar Mats occur on different scales from thin seams along stylolites and porous intervals to thick successions within the reservoirs. In the latter case, it raises important issues regarding field development options and well placement optimization. The Tar Mat in Field A, offshore Abu Dhabi, was detected in the first exploration well in 1969. In the 1970s and 1980s, 7 additional wells were drilled; the most recent well was drilled in 2007. Tar Mat sections were identified in all the appraisal wells.

The top of the Tar Mat can be clearly seen in the cored reservoir sections where it plugs the larger pore space. The bottom of the Tar Mat is not as simple to determine visually. Detection of Tar Mat is less reliable in cuttings and logs especially in tight zones and in the sections with lower reservoir quality. Thin section observations on the Tar Mat interval in the various wells appear to show that it is not present in heavily calcite cemented intervals related to paleo-water legs.

This hypothesis on the Tar Mat generation is based on Gulf analogues, in which the Tar Mat reflects a fossilized paleo-oil-water contact. In Field A, the top and bottom Tar Mat surfaces are not flat and their deformation reflects the growth of the structure after Tar Mat generation ended. The bottom Tar Mat surface is considered as the latest paleo-oil-water contact preserved in the field. These observations help in building a 3D model of the Tar Mat away from well control and, therefore, decrease the uncertainty in predicting the distribution of Tar Mat in the field. Better predicting the distribution of Tar Mat will have a significant impact in the successful development of this field.
Harnessing the Information Mammoth… New advances in data management in Engineering IT
Authors: Gibbons Steve
Published: June 2009

Today's oil & gas companies are struggling to meet the world's growing demand for energy. Oil & gas installations are getting ever more complex. New production capacity must be brought on line in ever-shorter timescales. More and more data is being created, bringing with it the challenges of how to access, share and control this information ‘mammoth’.

The cost of down time, whether planned or unplanned, rises with the oil price; production facilities require continual modification to extract more oil from depleting reservoirs, while squeezing more output from ageing downstream plant can incur operational and safety risks. There has never been greater need for better exploitation of the information embodied in oil & gas assets.

A number of factors have increased the information mammoth challenge: The increased volume and diversity of available information. IT advances have made it ever easier to create data; more and more applications and systems generate more and more data. Plants typically use many different, incompatible applications, so the information within them is effectively locked up in ‘silos’ – disconnected data formats that simply don't communicate with each other or make themselves universally available, and which are never uniformly updated.A stricter regulatory environment. This brings an increased need to audit business processes for compliance, and to be able to produce, at a moment's notice, reports, drawings, diagrams and other data to satisfy regulatory assessors' ever-growing demands.The continued trend towards larger multi-partner, multi-contractor and -subcontractor projects. How can data be shared from the very start? How can we make sure that data is updated correctly and that everyone has access to the right data at the right time? In short, how do we control the creation and dissemination of data?A change in demographics, leading to a shortage of skilled and experienced staff. Enormous experience and knowledge are locked away within a dwindling pool of highly skilled engineers. How can we unlock that experience and make it available to new trainees?
A Practical Guide for Identifying and Solving Air Cooled Heat Exchanger Performance Problems in the Field
Authors: Ellmer Marc
Published: June 2009

Well over 85% of all air cooled heat exchangers (ACHEs) in operation do not perform to their specified design values or end user requirements. As a result of this, during hot summer days, the product flow has to be reduced to achieve the required product temperature or pressure in the column.

Production losses during these days can reach as much as levels between 20 to 40 %. This can lead to losses amounting as much as US$ 500,000 to US$ 1,000,000 per year for one single limiting air cooler on a critical unit.

In this paper, we would like to offer you a practical guideline enabling your organization to identify basic air cooler problems and offer you also a few options to get more out of your ACHE without having the need for brand new air coolers or adding new bays.
Estimating Cementation Factor (m) for Carbonates Using Borehole Images and Logs
Authors: Akbar Mahmood , Steckhan Jan , Tamimi Masoume , Zhang Tianhua , Saner Salih
Published: June 2009

Carbonate reservoirs account for 60% of today's hydrocarbon production. Several giant carbonate fields in the Middle East are expected to be the dominant source of hydrocarbon production through the current century. Therefore, understanding carbonate reservoirs and producing them efficiently have become industry priorities and are likely to remain so.

In order to assess a possible hydrocarbon reservoir, hydrocarbon saturation needs to be determined with good accuracy. In 1942 Archie published a formula to estimate water saturation in reservoirs. In case of carbonates, the saturations computed by the formula are not always correct. The factors complicating the role of the formula are known as Archie Exponents, namely, porosity exponent (m, also known as cementation factor) and saturation exponent (n). Both exponents tend to vary quite often in the carbonate reservoirs. With the exception of cores, no reliable and well established techniques exist today that can give a good estimate of these exponents.

Estimating cementation exponent (m, porosity exponent) from the well logs is the main objective of this paper. The technique addressed in it is based on the assumption that the amount and pattern of cementation, caused by diagenesis, in carbonates is one of the factors controlling the value of m. Therefore in order to estimate it for carbonates, the cementation in them should be quantified. It was achieved through integration of electrical borehole images and petrophysical logs with the cores. The data on cementation was then used to estimate ‘m’ as a continuous curve for carbonate reservoirs.

The technique provides a unique way, which incorporates textural part of carbonates, to estimate cementation factor (m) for carbonates. It has been applied to carbonates of the Middle East and Europe with good results, which were verified by the core data and production results.
Normalized and De-Normalized PVT Methodology for Black Oil Simulation
Authors: Dabbour Youssef , Sener Ilhan , Al Marzouqi Mohamed
Published: June 2009

The procedure presented in this paper offers a way to combine and integrate black-oil PVT data obtained from several wells at various depths in a consistent and easy manner, especially when the PVT properties exhibit variation with depth and an EOS model is not readily available. In principle, it is similar to normalizing and de-normalizing SCAL data.

Although the method was primarily intended to honor and consistently take into account vertical variation of black oil PVT properties, it can also be used to reliably estimate oil PVT properties at elevations close to the GOC where reliable fluid sampling may not be possible due to gas coning or cusping during sampling operation.

The following are the main benefits of the method: Detecting and representing vertical variation of fluid properties in a reservoir or compartment especially when access to an EOS package is not readily availableVerifying reservoir compartmentalization by identifying lateral variations in PVT propertiesValidating PVT parameters and their variations with depthGiven sample PVT data from various depths, generating representative black oil PVT tables at any required depth for use in black oil simulation
A Modeling Feasibility Study Indicates Seismic AVO has Potential to Discriminate between Brine and Hydrocarbon in Middle East Carbonate Reservoir
Authors: Mahmoud Sabry L. , Othman Adel A. , Soroka William L. , Romero Tony , Smith Adrian
Published: June 2009

A seismic Amplitude Variation with Offset (AVO) feasibility study was successfully conducted to investigate the potential for fluid discrimination in a high porosity carbonate reservoir from a producing oil field in the Middle East. Gassmann fluid substitution was used to model the available well log data, which included compressional and shear sonic logs and density logs to produce synthetic well logs representing the reservoir at 100% fluid saturations of brine, oil and gas at reservoir pressure and temperature conditions. The modeled brine, oil and gas logs were used to calculate the AVO responses at the top and base of the reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-4 type AVO. The AVO results on the synthetic CDP gathers suggests that brine can be discriminated from hydrocarbon. These encouraging AVO results on synthetic data suggest that with good quality seismic data it might be possible to see a difference in AVO response between brine and hydrocarbon filled porous reservoir. An AVO case study was performed using available relative amplitude CMP gathers along a 2D seismic line extracted from a 3D seismic volume. The effects of key reservoir properties on AVO response were examined to help establish interpretation guidelines and better understand the potential for misinterpretation.
Direct Strength Measurements of Shale Interaction with Drilling Fluids
Authors: Hemphill Terry , Abousleiman Younane , Tran Minh , Hoang Son , Nguyen Vinh
Published: June 2009

Athough a crucial factor in drilling, the effects of the interaction between drilling fluids and shales on rock strength have not been directly studied in a laboratory setting. Instead, indirect methods, such as monitoring of shale swelling behavior, penetrometer tests, shale dispersion tests, etc., have commonly been used to gauge "relative" shale strength. In the results presented here, fluid interaction with two very different shales is reported and interpreted. One shale, from deepwater offshore West Africa, was tested with invert emulsion fluids (IEF) having varying water phase salinities. The second shale, taken from land drilling in Oklahoma, was tested with IEF and brine-based drilling fluids. The shale strengths were directly measured as functions of fluid chemistry and exposure volume using a specially-designed testing device located at the Poromechanics Institute (PMI) of the University of Oklahoma.

IEF having differing water phase salinity levels (ranging from 50,000 to 350,000 ppm calcium chloride) were first tested to determine changes in rock strength with exposure volume. Rock cohesive strengths and internal friction angles were then calculated, and the results showed changes in rock strength as a function of water phase salinity and exposure time. Additionally, the Oklahoma shale samples were exposed to calcium chloride brines having the same salinity levels (50,000 and 350,000 ppm) as the IEF, and the resulting effects on rock strength as a function of fluid chemistry and time were measured and compared to the IEF results.

The results clearly show that drilling fluid chemistry and exposure time have direct bearing on shale strength. This study should be interpreted as only the beginning of study of fluid interaction with shale: there is much to be learned here, yet much more in the future.
Estimation of Interwell Connectivity in the Case of Fluctuating Bottomhole Pressures
Authors: Kaviani Danial , Jensen Jerry L. , Lake Larry W. , Fahes Mashhad
Published: June 2009

Injection and production rates are often the most readily available data in a waterflood. Yousef and coworkers have shown that these data can be analyzed using a capacitance model (CM) to determine interwell connectivity and provide a tool for waterflood management. Although the existing CM performs well when tested with data from a reservoir simulator and in some field cases, it is less reliable in cases where bottomhole pressures (BHPs) are changing but not measured and/or where producers have been shut in for extended periods. This paper presents two new important developments of the CM to address these shortcomings: the segmented CM and the compensated CM.

The segmented CM can be used where BHP data are unknown. The compensated CM overcomes the problem of the requirement to rerun the model after adding a new producer or shutting-in an existing producer. If both BHP changes and shut-in periods occur, both the segmented and compensated CMs can be used simultaneously to construct a single model for a longer period of data.

In several simulated cases with fluctuating BHPs, the segmented and compensated CM successfully determined the true interwell coefficients. The conventional CM gives up to 70% error. In a field case, the segmented and compensated CM improved the prediction R2 by 15% compared to the existing CM. In this field example, there is good agreement between seismic impedance and results from the combination of the segmented and compensated CMs.

The existing CM, which is a good beginning, requires enhancements to be more versatile. The segmented and compensated CMs will make connectivity estimation more robust because pressure data are often unavailable or human interventions (e.g., work-overs) cause the flow rates to vary. Adapting the CM to tolerate BHP changes and shut-in wells, as we have done, provides this versatility.
Safe Behaviour as a Function of Consequences – B:f(C)
Authors: Tucker John
Published: June 2009

When seeking to achieve excellence in HS&E performance it is crucial to understand the nature of human behaviour and what drives our behavioural choices. There are many influences over behaviour but none quite as significant as our expectation of what the consequences of our actions will be for us as individuals and our teams.

Behaviour is mainly a function of such consequences (B:f(C)) and understanding this means that we are able to significantly influence people's choice of behavior when it comes to risk taking. HS&E excellence in high performing safety cultures requires a thorough appreciation of this simple fact in order to sustain continuous improvement and provide the opportunity for zero accidents.

It is possible in fact to achieve 100% safety critical behaviours that become habitual practices in relatively short time periods. However this can only be achieved and sustained if we truly understand the consequence drivers for individual and group behaviours and how to use these to the advantage of HS&E performance. It is also essential to embrace all parties in this process so that contractors import safe behavioural practices into client organisations and this requires careful consideration at the contract negotiation stage.

It is possible through effective consequence and therefore behaviour management strategies to achieve zero accidents in any operational environment.
Successful Application of Swell Packer Technology to Shut-off Water Production in Horizontal Wells – Case Studies from Onshore Abu Dhabi
Authors: Aboukshem Ali A. , Al Katheeri Abdulla B. , Kenawy Maher M.
Published: June 2009

The subject field has been on production for more than 35 years from multi-layered heterogeneous carbonate reservoirs. Due to the field's maturity, the water cut has started increasing gradually in some producers and, consequently, production from these wells has been affected awaiting implementation of artificial lift. To deal with the water production and prolong the natural flowing life of the wells, various water shut-off techniques available in the industry were evaluated in order to select the most suitable one that could be deployed in open-hole sections of horizontal wells.

This paper presents two case studies where a mechanical water shut-off technique, involving swell packers, was successfully applied in horizontal open-hole sections. The systematic approach adopted by the operator to build the business case, select the candidates, acquire the PLT data, execute the jobs, evaluate the performance of the water shut-off jobs and future plans are presented in this paper. The paper also addresses the conceptual application of borehole segmentation with swell packers to improve well performance.