bluuebunny/crossref_metadata_2025 huggingface dataset:
Bonny NAG Well and Reservoir Surveillance Improvement
Authors: Gardiner D. C. , Sadiq S. O. , Temisanren T. , Ukauku I. , Amos T.
Published: February 2011

In 2008 Well and Reservoir Management was recognised by SPDC as a key improvement area to arrest field declines and to maximise production and recovery from existing assets. One of the focus assets was Bonny Non Associate Gas (BNAG) field. The Bonny NAG field supplies Non Associated Gas to the Nigeria Liquefied Natural Gas (NLNG) plant, forming a key component of SPDC's supply to Trains 1 to 5 (450MMscf/d).

This paper describes how acquiring downhole pressure data and re-establishing proper well and reservoir management practice in Bonny field lead to improvements in non-associated gas production and reserves and reduction in uncertainty of predicted field performance for Bonny NAG.

After overcoming a number of challenges, a downhole data gathering programme for the Bonny NAG reservoir (one MRT and three static surveys) was successfully completed in October 2008, the first subsurface data acquired since 2005. The data obtained were analysed & interpreted and the result incorporated into an integrated reservoir, well, surface network modelling and optimisation system - "IPSM" to predict: (1) reservoir dynamics, wells potentials and performance; (2) identify surface network bottlenecks; and (3) gas deliverability forecast to NLNG.

Results of pressure transient analysis and material balance model in the IPSM indicated that the aquifer was much stronger than previously estimated from early pressure and production (data when less than 10% of GIIP had been produced). This led to a revision of the field's production strategy. Bonny NAG offtake, which had previously been restricted, was immediately increased by 25MMscf/d (maximum possible within surface facilities constraint) to accelerate and maximize production before water breakthrough occurs. Reserves figures were also re-assessed resulting in an increase in reserves booking in 2009. Also, a 14" transfer line was identified from surface network optimization efforts as the major bottleneck in the BNAG surface facility. Various options were considered to improve facility throughput. The result was a quick win project to engineer and install a 4" crossover line from the fuel gas plant to the BNAG facility. Work on the 4" crossover line started in February 2009 and was successfully completed and commissioned in October 2009, delivering an additional 14MMscf/d of sales gas from the BNAG plant to NLNG.
Development of Environmentally Friendly Oil Based Mud using Palm- Oil and Groundnut-Oil
Authors: Adewale Dosunmu , Ogunrinde Joshua. O
Published: February 2011

The development of an oil-based mud from palm oil and ground-nut oil was carried out in this work. It also compares the eco-toxicological properties of conventional base oil of diesel and vegetable oils derived from palm oil and groundnut oil.

A drilling mud was formulated with both palm oil and groundnut oil and standard additives were added. Complete mud check was conducted on the mud in order to determine the rheological properties. Toxicity of diesel, palm oil and groundnut oil were compared by exposing corns planted on humus soil beds prepared with palm. Also, groundnut oil-based mud with an oil/water ratio of 90/10 was formulated successfully. When the humus beds planted with corn were exposed to diesel, palm oil and groundnut oil, the corn exposed to diesel lost its greenness and died while that exposed to palm oil and groundnut oil retain its greenness. Palm oil-based mud having 90/10 oil/water ratio and groundnut oil-based mud exhibited a 20% and 12% average rate of growth without losing all its greenness.

Palm oil based mud formulated with different oil/water ratios congealed during the course of formulation. They exhibited high viscosity and progressive gel characteristics.

In conclusion, oil based mud developed using Palm oil and groundnut oil should be encouraged since its highly biodegradable, have better eco-toxicological properties and the cost of treatment of the cuttings are lower compared to Oil-based drilling mud formulated with diesel, mineral and conventional synthetic oil. They can also be a source of income to the farmers producing the palm oil in large quantity and help in the growth of the Nigerian economy since we can supply the palm oil to oil and gas companies that need it to produce their mud for drilling operations. In addition to these benefits, the oil based mud formulated with palm oil and groundnut oil is also functionally as efficient as the ones formulated with diesel and conventional synthetic oils.
A Proposed Cone Breakthrough Time Model for Horizontal Wells in Thin Oil Rim Reservoirs
Authors: Omeke J. E. , Livinus A. , Uche I. N. , Obah Boniface , Ekeoma E.
Published: February 2011

Understanding oil rim reservoir production dynamics is critical to successful development of thin oil rims. The interplay of subsurface factors and production constraints determine the dynamics of oil Rim reservoir production. Therefore in this study the impact of a range of sub-surface uncertainty on oil rim recovery was captured by employing the Plackett-Burman Design of Experiment (DOE) technique. The methodology involves a detailed generic oil rim simulation study. By employing the classical numerical reservoir simulation equation, assuming a negligible difference in fluid potential and applying material balance principle, the response surface model or proxy developed for cumulative oil recovery (Np) was combined with the cone breakthrough time equation and forms an integral part of the model. The model was developed for a thin oil column, between 20ft-60ft, sandwiched between a gas cap and aquifer.

The results from the model were compared with that gotten from a simulation study which gave reasonable value of cone breakthrough time with its equivalent water cut value.

The applicability of the model was tested by predicting the water breakthrough time for some selected major oil rim reservoir with gas cap and Aquifer in Niger-Delta.

The proposed model is reliable based on the fact that it captured some major sub-surface uncertainties (11 sub-surface parameters) that influences coning results while most pre-existing model do not. It can as well serve as a quick predictive tool before embarking on detailed reservoir simulation.
Investigation of Effect of Gas Injection Pressure on Oil Recovery Accompanying CO2 Increasing in Injection Gas Composition
Authors: Abbasi Saeed , Tavakkolian Mohsen , Shahrabadi Abbas
Published: February 2011

Gas injection is a common EOR method for increasing oil recovery factor. It is an economical method, especially in cases where the injection gas for such gas injection project is easily available.

In this study, the performance of gas injection into one of the Iranian reservoirs is investigated. Three sets of core flood experiments were conducted. Each run was conducted at different composition and injection pressure. The results of experiments revealed the fact that the recovery efficiency depends strongly on the injection pressure. It should also be noted that gas enrichment using components leading miscibility could increase the recovery. The optimum enrichment level was also an affecting factor, which controls the overall efficiency of gas injection.

In the last phase of this study, the minimum miscibility pressure of the injected gas and in-situ oil under operated conditions was calculated using simulation package. These simulation runs were conducted for different percentage of CO2 in injected gas. Results of these simulation runs were in a good agreement with experimental results. It was found that as the CO2 contents of the injected gas increased the minimum miscibility pressure (MMP) decreased. Displacing agent has a stronger effect in high pressures. It means that partial miscibility supplied by pressure buildup would lead to increasing recovery factor.
Comparison and Limitation Analysis of Approaches for Porosity Evaluation from NMR and Three Porosity Logs in Low Permeability Gas Sands with Bad Borehole
Authors: Wen Tang , Rui Xu , Ling-Ling Zhi , Xiao-Gang Wang
Published: February 2011

In this paper, we compare four methods of calculating reservoir porosity in low permeability gas sandstones with bad borehole condition, they are neutron-density crossplot technology, DMR technology, piecewise scale methods from acoustic time logging and SMR technology. The principle and limitation of these methods are analysised. When the borehole condition is good, these four technologies are all available, but in the wells with bad borehole, the technology of calculating reservoir porosity by integrating interval transit time logging and NMR logging, the neutron-density crossplot are recommended. For the NMR data acquired from CMR tool, the NMR porosity must be calibrated from deep lateral resistivity or deep induction resistivity logging, but these technologies are still the most useful because the computation process are simple and the odd error is less than DMR technology. The piecewise scale methods is also not recommended because it will spend too much time for log analysts.
Ants Can Do History Matching
Authors: Hajizadeh Yasin
Published: February 2011

This paper introduces a new stochastic approach for automatic history matching based on a continuous Ant Colony Optimization algorithm. Ant Colony Optimization (ACO) is a multi-agent optimization algorithm inspired by the behavior of real ants. ACO is able to solve difficult optimization problems in both discrete and continuous variables. In the ACO algorithm, each artificial ant in the colony searches for good models in different regions of the parameter space and shares information about the quality of the models with other agents. This gradually guides the colony towards models that match the desired behavior – in our case the production history of the reservoir.

The use of ACO in history-matching has been illustrated on PUNQ-S3 reservoir simulation model in North Sea with 45 unknown parameters. This model is fitted to multivariate production data coming from multiple wells. The ACO algorithm is also integrated within a Bayesian framework to quantify uncertainty of the predicted ultimate recovery.

Results confirm that Ant Colony Optimization can be used to generate multiple history-matched reservoir models and accurately predict the final recovery from the reservoir after 16.5 years. We have compared the history matching results of ACO algorithm with the Neighborhood Algorithm (NA) and NA coupled with a geostatistical framework applied to the same problem. This comparison indicates that ACO obtains the history matched models from fewer simulations. We conclude that Ant Colony Optimization is a fast, reliable and promising tool for reservoir history matching and uncertainty quantification.
A Novel Method to Model Water-Flooding via Transfer Function Approach
Authors: Sayyafzadeh Mohammad , Pourafshary Peyman , Rashidi Fariborz
Published: February 2011

Water flooding is one of the most economical methods to increase oil recovery. To maximize oil recovery during water-flooding, it is essential to provide a forecast of reservoir performance. Hence, various methods are used to simulate reservoirs. Although grid-based simulation is the most common and accurate method, time-consuming computation and demand for large quantities of data restrict the use of this method.

This study presents the development of a new method to predict the performance of water injection based on Transfer Functions (TF). This method is faster since it requires less data and the only requirements are injection and production rates. In this method, it is assumed that a reservoir consists of a combination of black boxes (TFs). The order and arrangement of the TFs are chosen based on the physical condition of the reservoir which is ascertained by checking several cases. The injection and production rates act as input and output signals to these black boxes, respectively. After analyzing input and output signals, unknown parameters of TFs are calculated. Then, it is possible to predict the reservoir performance.

Different cases are employed to validate the derived model. The simulation results show a good agreement with those obtained from common grid-based simulators. In addition, we found out that the TF parameters depend on the characteristics and the pattern of different sections of the reservoir.

This method is a rapid way to simulate water-flooding and could be a new window to the future of fast simulators. It enables prediction of the performance of water-flooding and optimization of oil production by testing different injection scenarios. The method also provides key parameters such as well connectivity.
Integration of In-Situ Combustion with Solvent Injection - A Detailed Study
Authors: D'Silva Jonathan
Published: February 2011

Production of heavy oil has always been associated with a lot of problems. A major one being the high viscosity of heavy oil due to which it does not flow easily into a producer well. In-Situ techniques like Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), and Vapor Extraction Techniques (VAPEX) are not mutually exclusive and it is becoming increasingly common for wells to be put through one of the techniques followed by the other so as to improve recovery rates.

The main purpose of this paper is to discuss the effects of combining the techniques of In-Situ Combustion with heavy hydrocarbon injection on the same heavy oil reservoir.

This paper discusses the effects of injecting different hydrocarbon solvents and gives a detailed explanation of this combination technique as an integrated unit, explaining the effects of In-Situ Combustion after hydrocarbon injection and its various advantages over using just a single technique.
Optimizing Production of Tight Gas Wells by Revolutionizing Hydraulic Fracturing
Authors: Ahmed Mansoor , Shar Amjad Hussain , Khidri Muzammil Ahmed
Published: February 2011

Tight gas wells are the wells having low permeability and the production of gas from these tight formations is the key issue in the industry. This paper includes the calculations, simulation work and enhanced engineering work to increase productivity along with the case studies.

Hydraulic Fracturing is usually conducted to resolve these kinds of situations. But the productivity can shoot up to 45-55%. It is done by revolutionizing the conventional hydraulic frzcturing through flow channel creation by enhancing proppant qualities like its strength and roundness, by lowering its crush and gel loading and improving gel breakers. Perforations are engineered and pumping technique and perforation strategy are combined causing channel formation. The combination of enhanced conductivity and effective fracture half length enables greater hydrocarbon recovery. Instead of flowing through proppant pack hydrocarbon flow through the channels created by proppant pillars giving effectively infinite conductivity and better fluids and polymer recovery and less fracture face damage. Via these techniques traditional losses in proppant pack conductivity from crushing, fines, fluid damage multiphase flow and non-darcy effects are eliminated meaning optimized production.
A Literature Analysis of the Coiled-tubing Drilling Processes
Authors: Kumar Sarvesh , Raj Parimal , Mathur Bakul
Published: February 2011

Effectively managing resources encompasses accurate engineering of target formations and prudent execution of project capital. Attaining both requires employing current technologies and implementing efficient operations, especially with today's challenging drilling environment and economic climate. The influence of improved technologies and the latest operational developments has lead to a significant impact in the arena of coiled-tubing drilling operations. Coiled-tubing drilling is a rapidly growing technology that has been used for various applications nowadays such as drilling shallow new wells, re-entry applications, sidetracking etc. This paper summarizes the hypotheses and theories relating to the causes and expectations of Coiled-tubing drilling in various reservoirs worldwide. The intent of the paper is to:Provide a concise compendium to the current understanding of the coiled-tubing drilling operations.Provide a comprehensive single-source review of the various projects successfully completed in the area and lessons learned.Help operators develop operational and design strategies for current and future projects, as well as to input parameters for simulating current and future projects.
Innovative Reservoir Modeling and Simulation of Unconventional Shale Gas Reservoirs Powered by Microseismic Data
Authors: Fazelipour Waleed
Published: February 2011

Shale-gas resource plays have started a new era for hydrocarbon exploitation in the energy industry worldwide. Latest advancements in drilling and stimulation are enabling technologies that make production of shale reservoirs economically viable. Multistage hydraulic-fracturing, the key technology to enhanced well performance, creates complex stimulated reservoir volumes, surrounding the wellbore, which are the main contributors to higher production profiles. Understanding the performance of such very tight, low permeability media and associated flow, introduces new challenges. Modern reservoir simulation powered by microseismic information, offers the best techniques to help understand them; evaluate the performance of wells; estimate the ultimate recovery; and help maximize the production.

Reservoir simulation provides cost-effective ways of understanding the shale-gas reservoirs behavior, and supplies information operators need to make quicker and better field development decisions. Reservoir simulation technology can optimize hydraulic-fracturing to maximize profitability and realistically simulate its effects in heterogeneous reservoirs involving multiphase, multicomponent fluid-flow and adsorption/desorption mechanisms. This is highly desirable to the industry. Properly describing the hydraulic fractures, their geometry and position; and characterizing reservoir/fracture properties are the main challenges.

This innovative work presents integrated workflows that demonstrate effective methodologies for capturing the essential characteristics of shale reservoirs; link seamlessly with microseismic fracture mapping software to import detailed descriptions of hydraulic-fracture attributes; offer flexible gridding schemes and populate the physical properties to enhance modeling of wells stimulated with hydraulic-fracturing. Ultimate conclusions of achievements include help generating more accurate forecasts which are critical for understanding wells performance and maximizing productivity.

This research has led to leading-edge reservoir simulation techniques to be utilized by the global E&P industry that enable operators to develop an early understanding of the performance of shale-gas wells where such detailed knowledge is vital to optimizing exploitation economics and estimation of reserves and resource potential.
Optimization of the Design of Transverse Hydraulic Fractures in Horizontal Wells Placed in Dual Porosity Tight Gas Reservoirs
Authors: Gorucu S. E. , Ertekin T..
Published: February 2011

The exploitation of gas from tight gas reservoirs has been increasing due to the advances in unconventional gas technologies and depletion of conventional gas resources. Drilling horizontal wells and placing transverse hydraulic fractures are needed to produce economically viable amounts of gas from tight sands. In this research, optimization of the design of hydraulically fractured horizontal well placed in naturally fractured tight gas sand reservoir systems was studied. A commercial reservoir simulator is coupled with artificial neural network (ANN) to create an expert system that can be used to design an efficient stimulation strategy. Reservoir simulation was used to generate production profiles of the reservoir system and, then, used to train the artificial neural network system. The ANN tools developed in this project consists of two parts: forward and inverse processes. In the forward process, an input data set that includes well and completion design parameters and reservoir properties is used to create an ANN toolbox to predict the production profile. In the inverse process, several design parameters and the desired production profiles were introduced into the input data to create an ANN toolbox to estimate the optimum design parameters. It is found that in both expert systems, functional links play a significant role in the success of the ANN tool. The results estimated by this developed toolbox can be used as preliminary information about the expected production profiles or the required wellbore and fracture design parameters for different cases.

This study shows that natural fracture permeability is the principal factor that determines the magnitude of the production. In addition, overall conductivities of the natural fractures and the hydraulic fractures are important factors affecting production.
Non-Darcy Flow in Tight Gas Reservoir of Travis Peak Formation
Authors: Khlaifat Abdelaziz , Arastoopour Hamid , Qutob Hani
Published: February 2011

The future of the energy sector in the coming years is expected to be significantly affected by unconventional gas resources. Most of the fundamental studies of flow in porous media are focused on the influence of the microscopic geometric structure on the macroscopic parameters. In order to address this question for flow through tight porous medium a series of single phase gas flow experiments were conducted. The considered porous medium sample was slot-and-solution pore type tight sand from the Travis Peak Formation with permeability in microdarcy range and porosity of 7%. Nitrogen and helium were the used gases. Single-phase experiments were conducted at different pressure drops and overburden pressures. They showed that the sample used is very sensitive to overburden pressure. Pore size distribution measurements, by mercury intrusion porosimetry and sorption isotherm, showed the existence of a wide range of pore size (from 0.4 to 400 nm) distribution. Moreover, the single phase gas flow through the sample particularly at low pressure is of Knudsen diffusion type. Thus, the gas molecules may slip at the wall of the capillary and the Klinkenberg formulation may be the approach to describe the deviation from Darcy’s law.
A Permeability Predictive Model Based On Hydraulic Flow Unit for One of Iranian Carbonate Tight Gas Reservoir
Authors: Haghighi Mehdi Bagheripour , Shabaninejad Mehdi , Afsari Khalil
Published: February 2011

Carbonate reservoirs show challenges to engineers and geologists to characterize because of their tendency to be tight and generally heterogeneous due to depositional and Diagenetic processes. The value of permeability is very valuable in dynamic reservoir modeling and simulation. Since permeability measurements during coring are very expensive and hard to be achieved, permeability predictive models are very desirable.

Among the various quantitative rock- typing techniques presented in the literature, the Hydraulic Flow Unit method (RQI/FZI) is more widely used. ‘D’ is a main carbonate formation in one of the giant gas reservoir in Iran. In this study, available routine core and wireline log data from four wells in this formation are assembled to develop Permeability Predictive Model based on Hydraulic Flow Unit.

For this purpose, first whole core data were used to characterize ‘D’ formation by several discrete rock type (DRT) with Hydraulic flow unit concept. Correlation accuracy of each discrete rock type was very good (R2>0.9). It is obvious that permeability can be accurately predicted from porosity if rock type is known. Eight different wireline log data were used to develop a permeability predictive model. For this, the whole log data for all wells were individually interpreted and normalized. After that, the values of the normalized logs were extracted at the exactly core plugs depths for each DRT. A convenient multivariate regression analysis was then performed to develop an explicit mathematical model for predicting permeability in uncored intervals and uncored wells. After some mathematical manipulation, the model was ready to use.

For testing the accuracy and reliability of this predictive model, the core data of one well which exists in the same formation was used. Results show that the permeability of predictive model matched well with the tested cored data in ‘D’ formation.
Well Logging and Formation Evaluation Challenges in the Deepest Well in the Sultanate of Oman (HPHT Tight Sand Reservoirs)
Authors: Al-Mahrooqi Sultan , Mookerjee Abhijit , Walton William , Scholten Sven , Archer Ray , Al-Busaidi Jokha , Al-Busaidi Hafidh
Published: February 2011

The high demand for natural gas in Oman has stimulated new exploration for gas resources that can be developed commercially. The Exploration Directorate in Petroleum Development Oman (PDO) has recently extended its exploration programme into the deeper parts of the sedimentary basins in North Oman. Reservoirs located here, principally in the Amin and Nimr formations, are expected to be tight (low porosity and permeability).

Data acquisition and petrophysical evaluation are major challenges when exploring the deep gas plays in North Oman. This is due to the hostile reservoir environment, i.e. high pressure and high temperature (HPHT). Current logging tools (wireline, LWD) are rated for operations up to 175°C and 20,000 psi. Data acquisition becomes significantly challenging as higher temperatures cause the logging tool electronics to fail.

This paper describes data acquisition and formation evaluation challenges for the deepest gas well drilled to date in the Fahud Salt Basin in the Sultanate of Oman. The first part of the paper discusses the logging plans, challenges and how, through optimised data acquisition, the objectives of logging programmes have been met. The planning phase started six months prior to well spud to manage the high uncertainty in the prognosed well TD depth and borehole temperature. The final well depth reached was 7145 m AH which is currently Oman’s deepest well. The maximum recorded downhole temperature was 195°C which posed a serious risk to successfully logging the last borehole section. Both LWD and wireline options were implemented and are discussed in the paper. Dual density tools were successfully used to overcome the borehole breakouts whereas flask Resistivity and HPHT tools were used to overcome borehole temperature limitations.

The second part of the paper describes formation evaluation methodologies we used in tight reservoirs. Improved porosity and water saturation calculations by integrating data from well logs, drilling, mud logging as well as geochemistry are discussed
Soda Ash as Gypsum Dissolver in 8" Production Line Case Study Gemsa Field, Gulf of Suez, Egypt
Authors: Riad E. H. , Abd-allah K. O. , Sarhan A. H.
Published: February 2011

Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can’t be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options (1).

Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.

This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level.

A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.

Based on extensive lab studies, Soda Ash was tested and applied in production line to remove the scale efficiently; the program was designed taking into consideration the nature of the scale.

The treatment program included three - staged process:The use of an organic solventThe main treatment (Soda Ash).The post flush stage (15 wt% HCl),

The job results were outstanding, where asProduction increased by about 2,000 BOPDLauncher pressure dropped by about 270 psi.Decrease the back pressure on our producing wells.Additional producing wells into production.Efficient cost /Bbl.
Application of High Resolution Micro-CT Imaging and Pore Network Modeling (PNM) for the Petrophysical Characterization of Tight Gas Reservoirs - A Case History from a Deep Clastic Tight Gas Reservoir in Oman
Authors: Riepe L.. , Suhaimi M. H. , Malaysia M. Kumar , Knackstedt M. A.
Published: February 2011

The paper provides a case history of the application of 3D imaging and Pore Network Modeling (PNM) technology to establish a direct relationship between rock micro-structure parameters from 3D via micro-tomographic images, and the simulation of petrophysical properties of clastic tight gas reservoir rocks in Oman. Tight gas reservoirs exhibit storage and flow characteristics that are intimately tied to the depositional and diagenetic processes. In particular, cores have significant primary and secondary porosity often dominated by clays and slot like pores. Accurately mapping the pore and grain structure and mineralogy in 3D and the interconnectivity of primary and secondary porosity illustrates the role 3D imaging plays in a comprehensive reservoir characterization program.

The computed petrophysical properties (e.g. porosity, permeability, formation resistivity factor, hydraulic radii and drainage capillary pressure) are compared with routine and special core analysis results measured on conventional core samples. The use of 3D micro-tomograms at different scales and PNM provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the static, elastic and dynamic rock properties even on rock fragments (2mm to 1cm diameter) that are not suitable for conventional core analysis techniques.

The presented case history demonstrates that the new 3D PNM technologies can also be successfully applied to the challenging tight gas reservoirs with low porosities and very low permeabilities for comprehensive reservoir characterization to optimize the development scenarios.
Drilling Waste Management: A Case Study of the Drilling Waste Management and Environmental Control in one of the Iranian Offshore Fields
Authors: Razmgir Seyed Mohsen , Afsari Meisam , Amani Mahmod
Published: February 2011

In upstream petroleum industry, one of the major operations that can potentially impact the environment is drilling. A major component of the wastes generated during drilling are the rock cuttings and the drilling fluids. The drilling fluids can have different chemical composition and various additives. Spilled or improperly disposed drilling wastes have the potential to harm plants and animals, and it should be managed to minimize risk to human health and the environment.

This paper presents the recent experiences in one of the Iranian offshore fields and their approach to develop and implement fluid wastes treatment and management exercises in drilling operations toward minimum impact on HSE in Khark Island. This paper reviews the drilling process, types of drilling fluid used and their composition and the methods to separate cuttings from drilling fluid.
Analysis of Geomechanical Data for Horn River Basin Gas Shales, NE British Columbia, Canada
Authors: Chou Queena , Gao Jordan , Somerwil Mick
Published: February 2011

Geomechanical data from the public domain for offset wells in the Horn River Basin, north–east British Columbia, Canada, were analyzed to obtain in–situ stress and rock mechanical properties in Devonian gas shale members that are under development. Static rock mechanical properties (e.g., Young’s modulus, unconfined compressive strength, peak cohesion) were calculated from wireline logs from offset wells for the shale members of interest. Derived static Young’s moduli for these shale members range from 18 to 31 GPa, and estimated unconfined compressive strength values range from 41 to 63 MPa. Assuming an average peak friction angle of 35°, the calculated peak cohesion values range from 11 to 16 MPa.

From three offset wells, the average vertical stress gradient at the top of the Devonian shales was estimated to be 24.8 kPa/m. Borehole breakouts and anisotropy of the sonic log velocities from offset wells were analyzed to estimate the current orientations of the in–situ minimum and maximum horizontal stresses. The predicted orientations of the in–situ horizontal stress were compared to the well azimuths of drilled offset horizontal wells surrounding the property of interest. This regional data show that the dominant orientation of the in–situ minimum horizontal stress is NNW–SSE. Hence, hydraulic fractures will propagate perpendicular to this in an ENE–WSW orientation. The average orientation of the horizontal wells drilled by the other operators in the basin to date is NNW–SSE, with a wide scatter of other well orientations. There was insufficient data in the public domain (e.g., oriented caliper logs) to assess whether orientations or magnitudes of the horizontal stress vary over the basin, or whether they are affected by small or large faults.

The average contrast of the magnitude of the horizontal in–situ stress between the shale members of interest was determined from the dynamic Poisson's ratio to understand the propensity for a hydraulic fracture to grow vertically out of zone. The result suggests relatively small contrasts may exist between the shale members. Recommendations were provided for obtaining site– specific in–situ stress data and rock mechanical properties.
Technical Limits of Tight Gas Fracturing in Oman – An Innovative Exploration Approach that Incorporates Global Practices
Authors: Curtino Joe , Harianta Rudi , Lie Winarsa , Judd Tobias
Published: February 2011

In Oman, hydraulic fracturing is an established tight gas completion technique in which fluid viscosity is used to build the necessary fracture geometry and transport proppant toward the fracture tip. This process has been very successful in reservoirs that demonstrate high gas permeability values and display normal stress regimes. However, in the deeper, hotter, lower-productivity horizons, these techniques are less effective.

A data collection and engineering method is required for local exploration and appraisal wells in this area because some of the tight gas reservoirs display unique physical properties that prevent actual analogue comparisons with other developed reservoirs. Furthermore, current industry practices, which are primarily influenced by the North American tight and unconventional gas market, merely transfer and apply different types of fracture design techniques. Here though, an engineering process is necessary to account for the reservoir properties and the potential impact on post fracturing well performance, along with potential scenarios for treatment failure.

Recent discoveries have occurred in the deep Amin formation that has resulted in an improved fracture design process. The technical challenges of fracturing a deep, high-pressure, high-temperature formation required evaluating alternative stimulation approaches than the traditional crosslinked gel fractures. This included deploying a high-density, crosslinked fracturing fluid incorporating a weighted sodium bromide–base fluid to generate high bottomhole pressures required to frac while not exceeding completion limitations. Likewise, the application of abrasive perforating technology has resulted in success where previous attempts using conventional techniques were not successful because of high near wellbore frictions and stresses. Finally, the evaluation of a hybrid fracturing technique has improved understanding of reservoir behavior in relation to hydraulic fracturing performance.

The continued emphasis and focus on low-permeability sandstone reservoir in this work is justified and useful by the continued importance of these reservoir types in Oman and other Middle East countries.
Detailed Modeling of the Complex Fracture Network of Shale Gas Reservoirs
Authors: Gong Bin , Qin Guan , Craig Douglas , Yuan Shiyi
Published: February 2011

Hydraulic and natural fractures are the key channels for shale gas to flow at economic rates. Fracture growth in shale gas reservoirs appears to be much more complex compared to most conventional reservoirs as massive multistage, multicluster hydraulic fracturing treatments are executed at many shale gas formations. It becomes crucially important to develop advanced approaches to model and simulate such a complex system to better understand the recovery mechanisms and optimize stimulation designs of shale gas reservoirs.

Most existing shale gas models are idealized dual-porosity models. The objective of this work is to model the actual network of hydraulic and pre-existing fractures based on geological interpretations and microseismic mapping results. The Discrete Fracture Modeling (DFM) approach is applied to represent each fracture individually and explicitly. This requires unstructured gridding of the fracture-matrix system using Delaunay triangulation and transmissibility evaluation between each pair of adjacent cells. The near-well effects are modeled in detail by refining the unstructured 3D grid to the point where we fully resolve stimulated fractures.

Simulations have been performed based on the detailed model of an synthertic shale gas reservoir with considering various mechanisms including adsorption/desorption, matrix-fracture transfer, and non-Darcy effects. Sensitivity studies by varying the production rate, pressure and hydraulic fracture parameters are conducted to provide guidance on optimizing stimulation and production schemes. Furthermore, to extend the application of this technique to large models, the Multiple Subregion (MSR) upscaling procedure is proposed to enable much quicker simulation runs. The high degree of accuracy provided by this technique is demonstrated by comparing the solution of the upscaled model with the corresponding fine-grid solution for a synthetic case.
Hydraulic Fracturing: Key to Effective Khazzan-Makarem Tight Gas Appraisal
Authors: Rylance Martin , Nicolaysen Arild , Ishteiwy Omar , Judd Tobias , Huey Troy , Giffin Wade
Published: February 2011

All tight gas project appraisals are inherently dependent upon the ability to execute effective fracturing treatments; that allow the determination of sustainable production rates; and hence potential project economics. Unlike the North American tight gas business, where thousands of wellbores are drilled each year and operational infrastructure and service quality is proven and in place; the International gas market challenges are significantly different. Often, the key risk with international appraisal; is not the presence of the hydrocarbons themselves, but more likely a competent and efficient execution of the fracturing process; that is essential in order to maximize gas inflow performance required for optimum well productivity.

The Khazzan-Makarem structures have substantial known hydrocarbon reserves; which to date have resisted an economic development. The unique reservoir challenges of these formations have been shown to require specialised operational, execution and technical expertise in order to be successfully appraised. The approach taken by the operator was to design the appraisal project with particular emphasis on the application of massive hydraulic fracturing treatments; as without successful stimulation, it was appreciated that the ability to evaluate well productivity and hence the development potential would remain elusive.

The result of close cooperation between the operator and the service providers, included planning the stimulation strategy, the number/sequence of wells, well types, fracture design, development of a matrix and selection criteria for technology deployment as well as operational issues associated with individual treatment execution. A locally tailored and carefully planned workflow was developed, that addressed the fracturing design process, the impact on the service delivery and the overall performance of this extensive project.

Information presented within this paper, will provide a complete understanding of the specific factors involved in tight gas stimulation (particularly in remote areas). Furthermore, it will demonstrate a methodical approach to the process of planning, execution, QA/QC and post treatment assessment.
North Oman Deep Gas Exploration Opportunity: From Drawing Board to Drilling Activity
Authors: Walton William , Scholten Sven , Aitken John , Al-Hakmani Abdullah , Al-Siyabi Hisham , Skaloud Dieter , Millson John
Published: February 2011

Early Palaeozoic-age non-associated gas fields operated by Petroleum Development Oman (PDO) in the Sultanate of Oman have traditionally comprised good reservoir quality sandstones located on three- or four-way dip-closed structural highs. While gas exploration success has continued over the last five years, this has been restricted to discoveries in much poorer quality ("tight") sandstone reservoirs. Significant challenges exist: target reservoirs are deep - over 4500 m (18,000 ft) with high reservoir temperatures (> 170°C). Porosities range from less than 3 to 10% with (ambient) permeabilities ranging from 0.001 to 1 mD.

These tight reservoirs have elevated pressures (above hydrostatic) and many wells record GDT (Gas-Down-To) situations (i.e. no GWC recorded). Furthermore, basin modelling indicates that peak hydrocarbon generation occurred during the Palaeozoic and Mesozoic and may have continued until Early Tertiary times in some areas.

A study was started in 2008 to analyse the above data applying a range of techniques including basin modelling, geochemistry, regional well results evaluation together with pressure data analysis and comparison with global analogues. This resulted in approval for a four well exploration campaign to evaluate diverse locations across north Oman addressing the quest for tight gas in a basin-centre setting. Drilling of the first exploration well started in late 2009 with the aim of proving the presence of deep gas accumulations and ultimately gain an indication of commercial attractiveness.

This paper presents the key criteria expected to influence the deep gas play prospectivity (i.e. presence of favourable reservoir, hydrocarbon charge and retention) and the steps to mature this opportunity. We also highlight an approach to progressing an unconventional gas opportunity in a challenging geological environment, in the Middle East, where the maturation of this resource type is currently in its infancy.
Petrophysical Rock Typing of Tight Gas Sands - Beyond Porosity and Saturation: Example from the Cotton Valley Formation, East Texas
Authors: Spain David R. , Liu Shujie , Devier Chuck
Published: February 2011

Laboratory benchtop nuclear magnetic resonance and mercury injection capillary pressure measurements were made on representative core plugs to facilitate rock property modeling of East Texas Jurassic Cotton Valley tight gas sandstones. NMR provides porosity data that is calibrated to downhole NMR and bulk density porosity measurements. Combined with mercury injection data, NMR provides information on the pore body -pore throat network characteristics of the reservoir sandstones. These data, combined with routine core data and petrographic observations, show that the Cotton Valley sands have low permeability, but that they are probably not capable of allowing water-free production.

Mercury injection data indicate that the bound (irreducible) water saturations in these rocks should be greater than 90% of the total Sw. This means that most of the water in the formation should be held in the reservoir by capillary forces and that gas production from these rocks should be relatively water-free. This is not the case.

NMR data indicate that there could be substantial water production with little gas flow. Combined data indicate that the reservoir sandstones have small to medium sized pores with small to medium pore throats. The rocks have low porosity and permeability overall, but are not tight enough to hold most of the formation water in the reservoir. Primary depositional facies, clay content, and subsequent diagenesis created complex pore geometry. NMR responses are controlled by the pore sizes; mercury injection behavior is controlled by pore throat diameters.

Improved permeability / petrophysical rock type models have been derived and used to calibrate downhole NMR measurements in both vertical and horizontal wells, resulting in improved recoverable gas in place estimates, fractional flow predictions, well targeting, and completion optimization in horizontal wells.
Aspects of Seismic Prospecting in Tight Gas Reservoirs
Authors: Philip Neil , Sheard Emma , Sutherland Fiona , Roome Barnaby , Taylor Brian , Margesson Richard
Published: February 2011

This paper describes some of the seismic aspects of BP’s experiences developing and exploring tight gas in Algeria. BP are involved in two projects where seismic has played a key role. The first project is a known gas field in its development stage, which requires infill well locations. The second is in its early exploration stage and requires a more fundamental understanding of the reservoir architecture.
Enhanced Geomechanical Modeling with Advanced Sonic Processing to Delineate and Evaluate Tight Gas Reservoirs
Authors: Adisornsupawat Kanitthorn , Tan Chee Phuat , Anis Leo , Vantala Aurifullah , Juman Reayad , Boyce Barry
Published: February 2011

A South East Asia exploration well was drilled into a gas-bearing large anticlinal 4-way Jurassic and Triassic age continental clastic with marine incursions. The well was designed to evaluate gas in tight sandstone with fractures. The host rock overall had low matrix permeability. Conventional methods of gas production from tight reservoirs usually require artificial stimulation such as some form of hydraulic fracturing. This well was no exception.

In order to optimize the hydraulic fracture design, a 1-D geomechanics study was requested to estimate hydraulic frac-ability of the rock. A 1-D Mechanical Earth Model (MEM) was constructed and fracture breakdown pressure was estimated as an outcome of the model. Mechanical properties are derived from logs data and calibrated against core with rock mechanics test data. Advanced sonic processing conducted before and after the fracing which give estimated pre- and post hydraulic minimum and maximum horizontal stress. These data was used to calibrate horizontal stresses profiles derived using poro-elastic strain models. The shear radial profiling was carried out allowing for identifications of the existence of stress within the rock. The advanced sonic processing also revealed the characteristic of stress anisotropy in the formation. Hydraulic fracture design and procedure was then developed based on the results of the model.

This paper intended to present the MEM using outputs from advanced sonic processing to narrow down the uncertainty of geomechanics parameters that are exist in the model.