bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysing Pressure Transient Data from Growth Fault Reservoirs in the Niger Delta
Authors: Obera Joseph H. , Peacock Anthony
Published: February 2011

One of the most conspicuous geological features of the Niger Delta is its growth fault pattern. Growth faults are a particular type of normal fault that develops during ongoing sedimentation, so the strata on the hanging wall side of the fault tend to be thicker than those on the footwall side. In this study, a detailed treatment is given of the transient pressure behaviour of a well located near a leaky boundary with unequal formation thickness on opposite sides of the barrier. These types of barriers are typical features of growth fault.

The results of this study generalize previously published works which assumed the thickness index for media on different sides of the fault was zero, one, or infinity. These assumptions are not always valid for growth fault reservoirs commonly found in the Niger Delta. One application of this work would be to facilitate detection of formation thickness on the other side of the fault without drilling a well in that location, this means reduced capital development cost thereby maximizing NPV.

The range of variables examined includes thickness index from zero to one and from one to infinity, also, the effect of transmissibility factor ranging from zero to infinity was included.

Based on this study, it was observed that for high values of the thickness index, the response is similar to that of a constant pressure boundary, while the behaviour resembles the sealing boundary characteristics for low values of the index.
Managing Reservoir Uncertainty in Gas Field Development Using Experimental Design
Authors: Itotoi Ibiada Harrison , Ojeke Akpoebi , Nnamdi Dike , Umurhohwo Jonathan , Benjamin Osaigbovo , AkaChidike Kanu
Published: February 2011

In a new field development, enormous time and energy are put in to identify and quantify both static and dynamic reservoir uncertainties. This could be very challenging when information is limited and not readily available. These data uncertainties vary from project to project depending on the quantity of reliable reservoir data acquired during the exploration and appraisal stage. The first step towards managing reservoir uncertainty in field development is to identify and quantify the key reservoir parameters that affect hydrocarbon in place and recovery. These parameters or factors are so many that their combinational effects result in multiple cases of development options, which will require many simulation runs. Stochastic and statistical data analysis coupled with Experimental Design(ED) have been used in recent times to reduce time and energy expended in managing key reservoir uncertainty parameters.

The case study presented in this paper gives an illustration of a successful ED application in a new gas field development. A detailed workflow was created to identify and quantify the uncertainties and risks in the dynamic model using probabilistic approach. This resulted in Probabilistic field forecasts that were further used to test surface development options in order to determine the optimal field development strategy that is robust to multiple realisations of reservoir uncertainties
A Systematic Approach to Effective Flow Property Determination for Deepwater Heavy Oil Evaluation
Authors: Uzoh O. J. , Ageh E. A.
Published: February 2011

Coarse scale modeling of deepwater turbidites requires that effective properties be developed to capture the fine scale flow behavior. In displacements with unfavourable mobility ratio, displacement instabilities at the shockfront may exist resulting in the occurrence of viscous fingers that reduce breakthrough recovery and increase gas and water production. Viscous fingering effects have been studied and demonstrated by laboratory experiments. The practical scale of fine scale models is usually too large to resolve viscous fingering effects. Hence evidence of viscous fingering has to be tested and appropriate upscaling applied at the fine scale modeling stage.

A two stage upscaling technique has been developed for heavy oil effective flow properties determination, a viscous fingering correction and generation of dynamic pseudos. The viscous fingering correction was done using the method of Clemens and Wit. This assumes that viscous fingers can be described by using a segregated flow approach. Upscaled rock relative permeability for viscous fingering was then used as input into the fine scale modeling. To upscale to the coarse scale model a history matching approach was applied to generate dynamic pseudos.

The application of appropriate effective flow properties to heavy oil characterization improves the quality of the production forecasts, and facilitates proper sizing of facilities.
Equation of State Characterization of a Deepwater Gas Condensate Field with Complex Geochemistry
Authors: Uzoh O. J. , Ageh Eby
Published: February 2011

An 8-component Equation of State 3D model coupled to Petroleum Experts’ GAP has been applied to characterize Deepwatergas field rich gas condensate reservoirs to capture compositional grading and phase behavior effects in the reservoir and production facilities. The Deepwatergas field consists of North and South reservoirs separated by a graben. The North reservoir contains a near-critical gas condensate (CGR of ~ 200 stb/MMscf) with evidence of compositional grading and a speculative oilrim while the South reservoir contains lean condensate (CGR ~ 60 stb/MMscf) with heavy oil and a tar mat at the base of the reservoir. Deepwatergas gas wells (one each in North Reservoir and South Reservoir) are tied back through a 26mile flowline to the host, hence understanding the hydraulics of the subsea flow system was also an important part of the performance evaluation, and key to future performance prediction and re-development decisions.

The results from the study helped explain the producing CGR in the North reservoir, which remained constant below field dew point, and also provided an assessment of gas compression requirements over the producing life of the field.
Improving Deepwater Core Recovery and On-site Handling Through Strategic Coring Protocol
Authors: Nnoaham Ike , Marchall Dave
Published: February 2011

A deep water coring protocol for a turbidite, unconsolidated environment was designed to improve core recoveries and accelerate plug samples needed for routine and special core analysis. The coring protocol was aimed at maximizing recovery by having onsite supervision and prescribing guidelines for WOB, ROP and Flow rate of mud system. It was also designed to facilitate well site freezing, stabilization and plugging using the half moon aluminum liner.

The results from the coring operations clearly demonstrate improved results with significant lessons and areas for improvement. This paper details the learnings and experience encountered during the coring operations.
Locating the Remaining Oil (LTRO) and Delivering Opportunities in a Mature, Declining Oil Field
Authors: Costier Laurent , Mitroshkin Vitaly G. , Hayes Hermélia Mbadinga
Published: February 2011

The Rabi oil field is situated onshore Gabon. It was discovered in 1985 and delivered first oil in 1989. The field reached peak production in 1997 (225 000 bopd) and has since undergone a steep decline (current production ~25 000 bopd).

Using extensive historical surveillance and production data (230+ wells, 70+ still flowing), a "Locate the Remaining Oil" initiative was launched to identify and unlock remaining reserves. A holistic evaluation of the WRM data was used to reach a static model of the fluids distribution, thus moving away from time-consuming, non-unique, full-field dynamic modelling for an oil field the size and the complexity of Rabi.

The updated static model, fluid contact maps for the different sectors and layers of the field alongside volumetric reconciliation helped to identify and locate remaining oil rims and unswept volumes. The LTRO initiative has resulted in an extensive portfolio of infill drilling targets and other activities which can be carried out in existing wells.

To increase the pace of hydrocarbon maturation, low CAPEX interventions such as heel perforations (when oil rims have moved above existing horizontal drains but can still be accessed higher up in the heel of the well) are going through an accelerated maturation process for short-term delivery whilst in parallel, a long-term activity plan focussed on maturing the rest of the portfolio is being developed.
Using Entrepreneurship Development and Corporate Social Responsibility as Strategies for Conflict Resolution in the Niger-Delta region in Nigeria
Authors: Raimi L. , Adeleke I. A.
Published: February 2011

The Niger Delta undoubtedly is the oil fountain of Nigeria. The region comprises of nine oil rich states of Abia, Akwa Ibom, Bayelsa, Cross Riveri, Delta, Edo, Imo, Ondo, and Rivers. The region's oil accounts for approximately 90 percent of the value of Nigeria's exports, but remains one of the least developed regions as a result of deliberate neglect. The neglect of the region for many years by successive governments in Nigeria degenerated into violent political crisis and armed conflict, which began to surge appreciably in the late 1990s and reached a dangerous dimension in 2009. The objective of this paper is to validate the proposal that using entrepreneurship development (ED) and corporate social responsibility (CSR) can be better strategies for conflict resolution (CR) in the Niger-Delta region in Nigeria. Based on the objective of this paper relevant literature on entrepreneurship and corporate social responsibility was reviewed to provide more insights into the various dimensions of the subject matter. More importantly, a survey technique was preferred for the study through the use of structured questionnaire to generate vital information on the topic from 600 Nigerians. The received responses of the respondents were tabulated and systematically analysed with simple frequency table and percentages, while the tentative research hypotheses were tested using Regression and Correlation Analyses. From the data analysis carried out and taking cognisance of the research questions, it was established empirically that entrepreneurship development and corporate social responsibility can be better strategies for conflict resolution in the Niger-Delta. In conclusion, palliative recommendations were given to Fedral Governemnt, policymakers of the multinational oil companies and stakeholders in the oil industry to help forged sustainable peace and energy development in the Niger-Delta.
Experimental and Artificial Neural Network Approaches to Predict the Effect of PVA (Poly Vinyl Acetate) on the Rheological Properties of Water and Crude Oil in EOR Processes
Authors: Rezaian A. , Kordestany A. , Haghighat Sefat M.
Published: February 2011

As consequence of pressure drop in oil reservoirs, production of oil will be difficult and EOR methods are used to improve recovery. In many countries Polyacrylamide is used for polymer flooding in EOR processes, but the problem is that Polyacrylamide is expensive also Acrylamide needs to be handled using best laboratory practices (such as having safe systems of work and wearing appropriate gloves, lab coat etc.) to avoid poisonous exposure since it is a neurotoxin.

In this paper, it is intended to investigate the effect of PVA (Poly Vinyl Acetate) on rheological properties (such as viscosity) of crude oil, water, and their mixture and see if it is possible to use this polymer in order to enhance oil recovery. Our objective is to determine the minimum amount of polymer to increase the viscosity of water and decrease the viscosity of crude oil simultaneously. Since even a small change of polymer amount requires extra costs, and experimental investigation of small polymer volume change could be time-consuming, an artificial neural network is developed to estimate polymer volume percentage.

Some of the experimental data used to test the network that showed a close agreement. Using 15 percent of polymer as optimum amount, 7.5 bbl of polymer is needed to recover 100 bbl oil. One should bear in mind that the polymer used here is not pure. If we could use pure polymer it may decrease the amount of polymer so the costs will decrease considerably.

Since this polymer is shear thickener for water, is not exorbitant in comparison to Polyacrylamide, and not biologically degraded, it could positively affect oil recovery under slow shear stresses.
Validating Reserves Estimation From A Simple Analytical Methodology with a Full-field 3D Model in a Giant Brown Reservoir
Authors: Sonde Adenike , Aboaja Ugochukwu , Oghene Ufuoma , Coker Trudy , Osho Rotimi
Published: February 2011

This paper presents the results of a 3D model constructed for a giant, densely faulted reservoir in one of the biggest fields in the Niger Delta. The study also showcases how simple analytical techniques applied in a technically thorough manner can achieve close or similar results to those from a calibrated 3D simulation model.

In carrying out this work, a detailed 3D model was built and calibrated for a very mature reservoir; incorporating results of the recently drilled wells in the field, revalidated integrated data and latest historical performance data. The reservoir, which is densely faulted by a conjugate system of synthetic and antithetic faults, is the largest in the field accounting for almost half of the field's resource volumes. The large number of NW-SE faults, coupled with the relatively high offtake rates from the reservoir, have throttled the activity of the otherwise infinite aquifer and led to severe pressure depletion in the reservoir. Consequently, a lot of the producers quit at relatively low water cuts (~40 − 50%). One of the objectives of the detailed modelling study was to investigate the benefits and gains of gaslifting existing and future new wells. Prior to this study, simple decline curve analysis (DCA) had been carried out independently on a well-by-well basis using estimated abandonment conditions under gasliftassisted flow to predict the recoveries and gains from gaslifting.

The prediction results from the full-field calibrated model compare very closely with the estimates from the individual wells DCA's and suggest that the DCA results can be used as 50/50 estimates for other reservoirs in the field where there are no full 3D models. This work therefore supports the fact that simple analytical methods, which are applied in a technically thorough manner, can still be used in the absence of full 3D models.
Optimizing Acid Gas Removal From Natural Gas Using Amine Mixtures
Authors: Erayanmen Wilson-Air
Published: February 2011

Removal of Acid gases from natural gas is currently a global issue; apart from it important in meeting the customer's contract specifications and for liquefaction process specification needs, it is also a measure for reducing the global CO2 emission. Natural gas process throughput rate is mainly based on the product specification control and the natural gas market drive for acid gas free products. This paper considered the gas treatment implications of the product specification; in profile trend with process throughput. The aim of this study is to investigate the possibility of using different amine mixtures as absorbent solvent in natural gas treatment process; using HYSYS software program as the simulation tool. A base case of Acid gas removal process (Non-Amine mixture based) is simulated using HYSYS 3.2 process simulator to create a steady-state process. The simulation program is then used to sensitized Amine mixture based process; through the modification of physical, thermodynamics and transport properties of the gas/amine process and also to develop an improved amine process that is environmental friendly. Simulation studies and analysis is carried out on an existing natural gas treatment plant. The simulation result shows that the application of amine mixture increases acid gases (C02 and H2S) pick-up in amine based solution with no corrosion effect. It also shows that regulating and increasing amine mixtures flow rate; encourages CO2 capturing capacity at low temperature, lowering the amine residence time in the stripper and reduces the tendency for CO2 emission.
Semi-Infinite Channel Sands: The Signature and Effects of Wedge Angles
Authors: Idigbe Koso I. , Obeahon Percy Paul
Published: February 2011

This paper presents the results of pressure-test numerical simulations performed on channel sands in order to capture the impact of reservoir heterogeneities on pressure transient behavior beyond what has been available to date.

Channel Sands, geological features characterized as long narrow reservoirs, were studied to model the effects of wedge angles, very important in the understanding of channel geometries.

The study shows that the effect of a semi-infinite channel having non-parallel sides can be obtained as a combination of a well test responses of a well placed between wedges. Varying the wedge angle was seen to affect the late-late time pressure response but did not affect the total system behavior. Also, varying The well location on a combined meander as well as the channel position in a combined meander, was seen to affect the middle-late times response but did not affect the total system behavior as a meander.

The ability to model these complex Channel bodies will greatly reduce the uncertainties associated with assigning the right geometries in reservoir studies. The estimation of reserves, a key factor in field development, is highly dependent on the size of the reservoir(s) in the field, a function of geometries.
Replacement of Existing ESD Valves with New SIL Rated ESD Valves: A Case Study of Production Optimization and Enhancement of Process Safety and Integrity in Kuwait Oil Company
Authors: Al-Khaledi Sadoun Mutar , Abdulaziz Naser , Bora Dwaipayan
Published: February 2011

Emergency Shutdown (ESD) valves play a vital role in meeting production and safety requirements in a process plant. On headers of a Gathering Center (GC), ESD valve assemblies are installed to protect the downstream processing equipment from over pressure, high level and other emergency conditions. ESD valves typically stay in open position for months or years awaiting a command signal to operate. Little attention is paid to these valves outside of scheduled turnarounds. The pressures of continuous production often stretch these intervals even longer. This leads to build up or corrosion on these valves that prevents them from moving. For safety critical applications, it must be ensured that the valves operate upon demand. The SIL-3 rated ESD valves complete with auto self-testing and acoustic leak detection are designed to operate upon demand. This paper discusses the enhancement of safety and integrity of the GCs following installation of new SIL-3 rated ESD valves in its headers.

Kuwait Oil Company is carrying out projects to enhance Safety Integrity Level (SIL) of header ESD systems by providing new SIL-3 certified ESD valves as replacement of the existing valves in its GCs.

This paper examines the numbers arrived in calculating various performance indicators of ESD valve reliability and interpret these for benefit of the engineers. It is evident that there is a marked improvement in the failure rate and hence integrity of new ESD valves compared to old system. This has also remarkably optimized production, leading to substantial savings.

If ESD valves are called into use, they have to work reliably, because the consequences of failure will be far more serious than the disruption, when they work. The new SIL-3 rated ESD valves are designed to operate when called for, thus enhancing safety and integrity of the GC.
Successful Improving Produced Water Treatment in Pul-A Field, Peninsular Malaysia Operations, PETRONAS Development and Production
Authors: Rosli Rosliza Hanim , Josli Hamidi , Osman Azmee , Hadi Sriyanta
Published: February 2011

Pul-A field is an oil producing field located about 260 km offshore Terengganu, eastern Peninsular Malaysia in a water depth of about 77 meter in the South China Sea (Refer to Figure 1). The field is equipped with oil and gas processing plant, gas injection facilities and gas compression system. Pul-A was brought to production in March 1978 with an average oil production of 1,400 barrels oil per day (BOPD). The oil production peaked at around 35,000 BOPD in 1979. Previously produced water was treated using a corrugated plate interceptor (CPI) unit prior to discharge. The water treatment is required to ensure the effluent water quality is in compliance with regulatory effluent discharged water requirement of maximum oil content of 40 parts per million (ppm). The CPI unit was down several times in 2005 and 2006 causing twenty daysproduction deferment with an estimated opportunity loss of USD 6.8 Million. In line with the effort to maintain the oil production by flowing high water cut wells, a new produced water treatment technology was chosen to replace the existing CPI unit. The new equipment is a vertical separator that is equipped with acombination of induced gas and cyclonic fluid motion to improve solids, water and oil separation. Pul-A team successfully installed the new equipment with challenging modifications and tie-in work in aging facilities. The unit that was commissioned in October 2010is capable of treating produced water up to 15,000 barrel water per day (BWPD).
Tight Gas Sands Development is Critical to Future World Energy Resources
Authors: Khlaifat Abdelaziz , Qutob Hani , Barakat Naiem
Published: February 2011

With the increased global demands on oil and gas, operators strive to maximize production by conducting more advanced drilling operations, such as extended reach, horizontal and high-pressure/high-temperature (HP-HT) drilling and are expanding globally into drilling unconventional resources. Unconventional gas resources offer significant gas production growth potential in the coming years, currently accounting for 43% of the US gas production. Tight Gas Sands (TGS) represents approximately 70% of the unconventional production and significant reserves are yet to be developed. Although "tight gas sands" are an important type of basin-centered gas reservoir characterized by low permeability, abnormal pressure, gas saturated reservoirs and no down dip water leg., not all of the TGS are Basin-centered gas (BCGAs). An intensive technology effort to both better understand tight gas resource characteristics and develop solid engineering approaches is necessary for significant production increases from this low-permeability, widely dispersed resource. Gas production from a tight-gas well will be low on a per-well basis compared with gas production from conventional reservoirs. A lot of wells have to be drilled to get most of the oil or gas out of the ground in unconventional reservoirs

However, economical production of TGS is very challenging as it exists in reservoirs with micro-Darcy range permeability and low porosity but has a huge potential for production in the future. Poor permeability results in lower gas production rates from TGS reservoirs. In order to economically develop TGS resources an advanced technology has to be developed and implemented. Most of the TGS reservoirs are characterized by being thick (hundreds to thousands of feet thick) and multilayered where their gas production rates can be enhanced by hydraulic fracturing. Although service companies have large capabilities for conventional/unconventional reservoirs but the used technology to drill, complete and stimulate tight gas reservoir is quite complex and the results are often unexpected and unforeseen. The appropriate completion methods and stimulation techniques in these reservoirs are dependent on many parameters and variables, such as depth, pressure, temperature, capillary and overburden pressures and the number of sand layers.

This paper provides a technical overview of the state of the art technology used to develop those reservoirs. This work takes a multidisciplinary approach to better understand how gas can be produced from tight gas sand reservoirs. Two real case histories will be presented and discussed; Travis Peak formation in eastern Texas, USA; and Risha gas field in eastern Jordan.
Numerical Well Testing Using Unstructured PEBI Grids
Authors: Deng Hui , Bao Xia , Chen Zhangxing , Wang Ruihe
Published: February 2011

History matching is challenging for low permeability gas reservoirs because of significant differences between the static properties in a geostatistical model and in-situ properties measured from well testing. The literature has documented that reduction of in-situ permeability due to overburden pressure can be in two orders of magnitude. Numerical well testing provides a way of tuning a static model with dynamic well testing information. However, a traditional single well testing model using Cartesian LGR (local grid refinement) is not ideal for predicting the pressure transient behavior. Furthermore, a stand-along well testing conditioned model cannot be fully coupled into a full-field model to honor the flow regime.

This paper presents a methodology of using a PEBI (perpendicular bisector) grid in a simulation model to match well test data for a low permeability gas reservoir in Canadian Foothills. A PEBI-LGR grid is created around the well and a vertical hydraulic fracture is implemented to match the post fracture pressure build up. History matched parameters include static properties and hydraulic fracture properties such as fracture half length and fracture permeability. Finally, well testing conditioned effective properties will be stochastically populated into the simulation model for the full field history matching. In conclusion, the PEBI gridding technique links well testing with reservoir simulation and provides the most efficient workflow in modeling unconventional gas reservoirs with multi-stage hydraulic fractures.
Extending Well Productive Life by Acid Re-fracturing in a High Pressure/High Temperature Tight Gas/Condensate Carbonate Reservoir in the Jurassic Formation of North Kuwait
Authors: Kabir Mir , Dashti Qasem , Singh J. R. , Pradhan San Prasad , Nugraha Ikhsan , Hai Liu , Al-Ghadhban Hamed
Published: February 2011

One of the most common strategies to effectively produce from tight gas carbonate reservoir is by completing the wells with acid fracturing technique, where the etched fracture half length alters the flow pattern from formation in to the wellbore with its high conductive flow path.

The treatment success, apart from operational aspects, is also measured by addressing the issue of fractured geometry created, zonal coverage achieved and the actual well potential based on its petro-physical and rock mechanical properties and relate this to well’s production behavior. In the high pressure/high temperature tight rock formation with minimum number of natural fractures, it is very common to observe immediate production gain following an acid fracturing treatment.

The well in discussion was acid fractured 3 years earlier with almost 90% of cumulative production occurred during the last one year. It was observed that it is declining faster than expected. Review of the well performance led to two main possible causes, i.e. reservoir pressure decline and reduction in fracture length/conductivity. Acid re-fracturing strategy was considered and decided to restore the well’s productivity by further extending the fracture half length by enhancing the fracture conductivity.

The results showed that Productivity index (PI) increased by 2.5 folds during the post treatment production test. However, after 3 months of continuous production, the PI declined down to 1.2 folds despite the pressure build up performed indicated fracture conductive behavior. This paper discussed key lessons learned to further improve the outcome by integrating production analysis, reservoir quality evaluation as well as stabilized production expectation with stimulation approach during candidate evaluation process.
A Better Understanding of Finite Element Simulation for Shale Gas Reservoirs through a Series of Different Case Histories
Authors: Jayakumar R.. , Sahai V.. , Boulis A..
Published: February 2011

Production from the extremely low permeability reservoirs found in shale gas plays results in very large pressure gradients at and around the sand face. Finite-element modeling technology, in which a large number of closely-spaced nodes are placed near hydraulic fractures, is the best approach for replicating the reservoir and completion complexity required to model horizontal shale gas wells. The primary objective of this work is to demonstrate how the performance of three Haynesville Shale gas wells were modeled using this technology. Each of these three wells exhibits the large early production decline typically observed in the Haynesville. Case histories for these wells show how the finite-element software can be used to simulate the mechanisms thought to contribute to the observed production decline. The workflow used to model performance demonstrates how petrophysical, stimulation, and flow modeling are utilized to understand the key reservoir and completion mechanisms that affect production behavior of shale gas wells.
Effects of Block to Block Interaction on Oil Recovery from South Pars Oil Layer
Authors: Sani Reza Rezaei , Afsari Meisam , Amani Mahmood
Published: February 2011

This article investigates the effects of block to block interaction, gravity drainage and capillary continuity, on oil recovery from South Pars oil layer during primary production and gas flooding. For choosing the best oil production and EOR scenarios, the necessity of investigations like this study is obvious. In addition this work can be extended to other Iranian fractured reservoirs.

Sensitivity analyses during primary production and immiscible gas injection are performed by using CMG/IMEX simulator1 based on a very simple single porosity model but very close to dual porosity/permeability modules of this simulator.

The objectives of this article are: Investigation of main matrix-fracture fluid exchange mechanisms (like gravity drainage and capillary imbibition) during primary production from South Pars oil ring and gas injection into South Pars oil ring. Emphasizing the importance of issues such as capillary continuity between matrix blocks, reinfiltration of fluid from higher to lower blocks and block shape on flow processes and oil recovery during primary production and immiscible gas injection in South Pars oil layer. By characterizing the fractured/non-fractured reservoirs and finding the main oil recovery mechanisms, reservoir management can be done scientifically at the best time and at the best location.
Drilling Optimization in Unconventional and Tight Gas Fields: An Innovative Approach
Authors: Holdaway Keith R.
Published: February 2011

The majority of the technically recoverable natural gas is present in unconventional reservoirs such as tight sands, shale, and coal beds. On account of the implicit high costs associated with these unconventional and deep gas assets, it is of paramount importance to garner as much knowledge from potentially disparate and limited data sources. The objectives must be minimization of drilling and completion times, constraint of risks, quantification of uncertainty and ultimately maximization of the lifetime of a well’s productivity.

This paper illustrates an advanced analytical methodology that aggregates and integrates data from a multitude of sources, performs a robust quality control, correlates and discovers patterns to enable engineers to determine more efficient and accurate exploitation strategies. It proposes an approach based on an advanced analytical framework that introduces an exploratory data analysis step for reservoir characterization, followed by determination of key production indicators and multivariate methodologies to classify wells. With improved understanding of inherent correlation between geology, reservoir, rock mechanics, frackpack process and proppant fluid and well performance, it is feasible to cluster the wells in accordance to the overriding production indicators, thus dividing the field into clearly defined segments. The statistical output enables mapping via a transparent classification of best possible wells to known geology and reservoir conditions to identify and locate poorly-drained zones and effectively neccessitate less drilling to achieve production targets.
Hydraulic Fracturing of Naturally Fractured Tight Gas Formations
Authors: Leguizamon Javier , Aguilera Roberto
Published: February 2011

A workflow is presented for modeling actual hydraulic fracturing jobs in tight gas formations of the Western Canada Sedimentary Basin (WCSB). Matching of hydraulic fracture length and resulting gas production from past jobs provides a learning curve that allows design optimization of future fracturing jobs.

Key parameters needed for modeling the design of hydraulic fracturing jobs in these types of formations are discussed and include properties such as porosity (matrix, natural fracture and isolated or non-connected), permeability (matrix and natural fracture), water saturation (matrix and natural fracture), shear velocities (even when direct measurements are not available), Poissons ratio, shear modulus, Young modulus, Biot constant, overburden, pore pressure, and net stress. The critical evaluation of these properties provides a valid representation of the tight gas formation and what the natural gas production outcome from the hydraulic fracturing job might be. Important recommendations to achieve a correct integration of logs, well testing, production decline analysis, and 3D modeling of the hydraulic fracturing job are also presented; as wells as an understanding of the differences that can arise from each source of information. The paper incorporates petrophysical and new linear-dominated well testing and production decline analysis methods using triple porosity models for matching petrographic work and production decline; and for quantifying rock properties such as natural fractures and slot porosity, intergranular porosity and isolated non-effective porosity.

It is concluded that even though each tight gas reservoir is unique and as such, should be considered as a research project by itself, the workflow presented in this study could prove to be of value in other regions of the world where tight gas formations are present.
Well Completion Strategy and Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Seale Rocky , Snyder Daniel J
Published: February 2011

First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.

How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 21 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, mechanical systems (OHMS) and production is compared to offset wells and field averages.

Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
A Comprehensive Approach to Surveillance in Appraisal of a Tight Gas Project in Central Oman
Authors: Clark Robert A , Al Busafi Badar , Adil Imtiaz , Al Lawati Hussain , Huggins Paul , Rainey Steve
Published: February 2011

BP’s Khazzan-Makarem (KM) appraisal project is located in Central Oman. BP committed to appraise four deep tight gas reservoirs and has drilled seven wells to date. An Extended Well Test (EWT) facility is designed to provide a long term (multi-month) flow test of those wells.

Basic information relating to trap, seal, areal extent, and Gas-in-Place (GIP) is not the most significant problem in this appraisal project; the most important issue is long term well performance. The tight gas nature of these reservoirs results in considerable uncertainty in prediction of future deliverability. It is not uncommon for tight gas wells to achieve excellent flow rates after fracture stimulation, yet decline precipitously over a short period of time (typically months) once on production. Prediction of well performance based on this early flow rate is a highly unreliable indicator of long term performance. This can result in drastic miscalculations for Full Field Development (FFD) planning and economics.

Extensive surveillance activities are critical to evaluate this uncertain behavior. An examination of stimulation, well testing and Pressure-Build-Up (PBU) analysis in these wells provides the starting point for understanding well deliverability.

BP’s KM appraisal wells were planned to selectively target reservoirs addressing variations in reservoir quality and continuity. Completions were designed from the start, to facilitate extensive stimulation programs. Surveillance programs were constructed with permanent down hole gauges (PDHG) to provide critical real time information about the stimulation efforts, well testing, fluid composition analysis, and extreme long term (~ 1 year) PBU. All of this effort provides guidance in planning the EWT facility for an extended flow testing campaign which will feed into FFD planning. Achieving commercial rates in tight gas reservoirs in Oman has proved to be challenging. However this comprehensive appraisal and surveillance program is providing a growing level of confidence in the development potential of the Khazzan-Makarem project.
Role of Geomechanics in Appraisal of a Deep Tight Gas Reservoir: A Case History from the Amin Formation in the Sultanate of Oman
Authors: Perumalla Satya , Moos Daniel , Barton Colleen , Finkbeiner Thomas , Al-Mahrooqi Sultan , Weissenback Markus , Walton William , Al-Siyabi Hisham
Published: February 2011

Appraisal of deep tight gas reservoirs offers many challenges, including production rate predictions when wells are drilled overbalanced. Overbalance leads to near wellbore porosity / permeability damage to the rock matrix and fractures. Furthermore, poro-elastic effects due to invasion contribute to difficulties initiating and propagating hydraulic fractures. Damage to natural fractures intersecting the well can prevent their detection leading to missed productive intervals.

Alternatively, under-balanced drilling (UBD) can avoid these effects and thereby better indicate the gas potential of these reservoirs. However, not all reservoirs are suitable for UBD as there can be a greater risk of mechanical wellbore instability. Hence, geomechanical analysis prior to drilling can help evaluate the feasibility of UBD operations.

Formation evaluation in UBD conditions also poses many challenges due to technical (temperature and pressure) limitations of tools and higher uncertainties with petrophysical calculations. Conventional core to log and porosity/permeability relationships are often inappropriate where matrix permeability is extremely low and fractures contribute to flow, therefore alternative ways of understanding and evaluating the reservoir are essential.

In this paper, we demonstrate how geomechanics was used in formulating a strategy for appraisal of a well placed in a tight gas reservoir and also as a decision support tool while drilling.

We present here an analysis of data from the Amin reservoir in the Fahud Salt Basin, Sultanate of Oman, where mechanical borehole failure due to in-situ stresses, pore pressure and rock properties was successfully simulated to understand the mechanical behaviour of the rock matrix and natural fractures which played an important role in controlling the gas flow profile.

Planning of this Amin reservoir well involved geomechanical analysis prior to well spud to evaluate UBD feasibility based on offset well data, followed by updating the models as the well progressed. Evaluation of natural fractures from image logs and identifying sets of critically-stressed fractures (hydraulically-conductive fractures) was an important component of the geomechanical analysis that played a key role in supporting the appraisal strategy.
Seismic Technologies for Unconventional Reservoir Descriptions: Wamsutter Field Case Study
Authors: Hornby Brian , Geetan Rosemarie
Published: February 2011

As part of a significant seismic technology effort, the BP Wamsutter Seismic Integration team conducted two field trials during 2006/2007- a surface seismic field trial and a borehole seismic field trial. The borehole seismic field trial consisted of a 3D Vertical Seismic Profile (VSP), as well as a four-well crosswell seismic campaign. The 3D VSP was acquired to further our understanding of seismic technical limits within the field, demonstrate the value of enhanced temporal resolution to reservoir characterization, and to test the viability of borehole seismic as a development tool for infill planning. The complex, heterogeneous, and thin-bedded nature of these tight reservoir sandstones make detailed reservoir characterization from surface seismic data extremely challenging. For Wamsutter, pre-acquisition 1D modeling from existing well data allowed theoretical limits of vertical seismic resolution to be compared to existing seismic data. Significantly higher frequencies (double the bandwidth) were successfully achieved with the 3D VSP as compared to existing and newly acquired surface seismic data. Prestack depth migration of the 3D VSP yielded excellent imaging results, which have allowed enhanced stratigraphic description of a very complex reservoir. Additional work explored the potential to use 3D VSP in conjunction with the surface seismic data for seismic imaging without a velocity model. Analysis, interpretation and integration of the VSP data has greatly progressed our understanding of the potential increase in the value of "designer" or fit-for-purpose seismic across the Wamsutter Field and beyond.
Clinical Associations with a Placental Diagnosis of Delayed Villous Maturation: A Retrospective Study
Authors: Higgins Mary , McAuliffe Fionnuala M. , Mooney Eoghan E.
Published: February 2011

Delayed villous maturation (DVM) is a spectrum of placental disease characterized by decreased tertiary villus formation, reduced vasculosyncytial membrane formation, and, in its more severe forms, increased large bullous villi. In some series it has been associated with an increased risk of stillbirth in the late third trimester, but overall there are few data on its significance. The aim of this study was to assess perinatal factors associated with, and the clinical significance of, the finding of DVM on placental histology. This was a retrospective study investigating all pregnancies with DVM diagnosed on placental histology in a tertiary level unit between December 2001 and August 2006. Over a 6-year period, 2915 placentas were triaged for histopathological assessment, representing 6.1% of all 48 054 deliveries in this time period. One hundred ninety (6.3%) of these selected cases showed DVM. Fifteen placentas from infants with less than 34 completed weeks of gestation were excluded, leaving 175 for further analysis. When compared with controls matched for gestation and delivering within the same time period (n = 175), DVM was significantly associated with pregestational diabetes (8% vs 2.8%, P < .05; relative risk 2.8 [95% confidence interval 1.03–7.6]), gestational diabetes (8.6% vs 3.4%, P < 0.05; relative risk 2.5 [95% confidence interval 0.99–6.3]), and prenatal or intrapartum intrauterine death (8.6% vs 0%, P < 0.05). Delayed villous maturation is associated with both gestational and pregestational diabetes mellitus and with perinatal death.
Diversity of the digenean fauna in sparid fishes from the Lagoon of Bizerte in Tunisia
Authors: Gargouri Ben Abdallah Lamia , Antar Rym , Maamouri Fadhila
Published: February 2011

A total of 24 digenean species belonging to 10 distinct families (Derogenidae, Faustulidae, Fellodistomidae, Gyliauchenidae, Hemiuridae, Lepocreadiidae, Mesometridae, Monorchiidae, Opecoelidae and Zoogonidae) were recorded in sparid fishes from Bizerte Lagoon (northern Tunisia). The diversity of the digenean fauna of sparid fishes from this locality is compared to that recorded from the Gulf of Tunis. Prodistomum polonii, not detected before, was found in Sarpa salpa. Aphallus rubalo, Derogenes latus, Holorchis micracanthum and Pachycreadium carnosum previously recorded from sparid fishes on the Tunisian coasts were absent during this study. Allopodocotyle pedicellata, Lepocreadium pegorchis, L. album, Proctoeces maculatus, Magnibursatus bartolii and Macvicaria maillardi were reported in hosts not previously reported for the Gulf of Tunis. Generally, prevalence was higher in fishes from Bizerte Lagoon but abundance and mean intensity were higher in Gulf of Tunis. Except for Lithognathus mormyrus, Sarpa salpa and Sparus aurata from Bizerte Lagoon, which show higher digenean diversity, the other sparid fishes have a lower diversity compared to those from Gulf of Tunis. The species richness of digeneans in B. boops was the same in the two areas studied.
Ultrastructure, characteristic features and occurrence of Nosema leptinotarsae Lipa, 1968, a microsporidian pathogen of Leptinotarsa decemlineata (Coleoptera, Chrysomelidae)
Authors: Yaman Mustafa , Özcan Nejla , Radek Renate , Linde Andreas , Lipa Jerzy
Published: February 2011

This paper presents the ultrastructure and characteristic features of Nosema leptinotarsae infecting L. decemlineata collected in Trabzon (Turkey). Fresh spores are oval, 4.69 ± 0.19 μm in length and 2.43 ± 0.12 μm in width (n = 50). The spore wall is thick and measures 180 to 250 nm and consists of a clear endospore (130 to 170 nm) and an electron-dense, uniform exospore (50 to 80 nm). The polar filament is isofilar and has 15–16 coils. The well-developed polaroplast has a lamellated structure with thin lamellae. The ultrastructural features of Nosema leptinotarsae differ from those of other microsporidia infecting chrysomelids.
Phytoplankton dynamics in the reservoir lake "Żur" on the pomeranian Wda River
Authors: Wiśniewska Marzena
Published: February 2011

One hundred thirty eight taxa of plankton algae were identified in the Żur Reservoir (Cyanoprokaryota 27, Dinophyta 5, Euglenophyta 4, Chrysophyceae 6, Bacillariophyceae 40, Chlorophyta 56). The biomass of spring and summer plankton consisted mainly of diatoms. Based on the species composition, phytoplankton biomass, concentration of chlorophyll a and TSI, the Żur Reservoir was generally classified as moderately eutrophic with distinct trophic diversification of the water at particular studied sites.
Ilona Janyšková, Helena Karlíková (eds.). 2009. Studia Etymologica Brunensia
Authors: Bubenik Vit
Published: February 2011

Ilona Janyšková, Helena Karlíková (eds.). 2009.Studia Etymologica Brunensia