bluuebunny/crossref_metadata_2025 huggingface dataset:
The Role of Diffusion for Non-Miscible Gas Injection into a Fractured Reservoir
Authors: Yanze Yannick , Clemens Torsten
Published: September 2011

To improve oil recovery from pervasively fractured reservoirs, gas injection can be considered. In such reservoirs, the fractures typically provide the flowpaths but contain a limited amount of the oil whereas the matrix often has orders of magnitude lower permeabilities but contains the oil.

To improve oil recovery from such reservoirs, gas/oil gravity drainage can be applied. In this process, a gravity stable displacement can be achieved.

If gas is injected which is not in equilibrium with the oil, the non-equilibrium gas components diffuse from the fracture system into the matrix and the components of the oil diffuse towards the fracture system. This results in a modification of the properties of the oil affected by diffusion and gravity drainage rates accordingly.

The effects of non-equilibrium gas injection into a pervasively fractured reservoir were studied at the example of an Austrian reservoir. This type of gas injection results in a zone of decreased oil viscosity for gases such as CO2 and CH4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity drainage rates.

The results show that the effect of diffusion can increase cumulative oil production up to 25 % compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing and matrix block height. While for some of the parameters, the effect of diffusion scales with the square root of time (e.g. permeability), for others an exponential relationship has been determined (fracture spacing).

The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning non-equilibrium gas injection and how large the error could be in case that diffusion is neglected.
Water Injectivity Tests on Multilayered Oil Reservoirs
Authors: Barreto A.. , Peres A.. , Pires A..
Published: September 2011

Completion of water injection wells directly into production oil zone has become a common practice on offshore development projects. Hence, injectivity tests started to play an important role for reservoir management of these fields. In an injectivity test a single phase (water) is injected continuously for a certain period of time in an oil saturated zone followed by a falloff period. Though single-phase flow of a slightly compressible fluid analysis methods are well documented in literature, transient two-phase solutions and analysis techniques need further development. Analytical solutions that model pressure behavior during a single layer injectivity test were recently presented in literature. This paper presents a new analytical solution for a vertical water injection well completed in a layered oil reservoir of infinite extent. To the best authors’ knowledge, the proposed solution was not presented before.

Two phase immiscible displacement of oil by water in a multilayer reservoir is modeled by a system of partial differential equations. This system is weakly non-linear and can be decoupled by assuming steady-state conditions in the two-phase region. The solution is then obtained by the method of characteristics on the two-phase region coupled with the infinite acting single phase radial flow solution valid for the oil region. The solution derived in this work can be used to compute the wellbore pressure, injection rates and the water front for each individual layer without resorting of a numerical flow simulator. Parameter estimation from field data can be obtained from the proposed solution if a production logging rate profile is available.

Two synthetic examples are used to verify the solution derived in this work. The first example considers the behavior of a two-layer reservoir whereas in the second case a reservoir with seven layers is analyzed. The wellbore pressure is compared to a finite difference simulator. An excellent agreement is obtained for both examples.
Thin Bed Sand Shale Sequences Decoded by NMR Answers
Authors: Potts Robert , Smith Charles H. , Ramakrishna Sandeep
Published: September 2011

The Tesnus sandstone was deposited during the late-Mississippian/early-Pennsylvanian time in clastic debris flows. In general, it consists of a series of sand/mudstone turbidite sequences that are deposited in thicknesses varying from a few hundred to several thousand feet overall. The uppermost Tesnus consists of amalgamated and thinly-bedded sands that contain poor–good vertical connectivity and tend to have better ultimate recoveries. The lower sands are layered sands consisting of thin interbedded sandstone and shale sequences with poor vertical connectivity.

These sands present an analysis problem for conventional open-hole logs, as standard porosity interpretation is not directly related to well performance as a result of the high clay content and poor permeability. Hydrocarbon production from the Tesnus is primarily natural gas with a varying amount of CO2 content, ranging from 1—30%, and very minor amounts of formation water. Sand and shale sequences can be as thin as 1–2 in. These thin zones could have high permeability zones next to zones of no permeability. Thin bed logging approaches were used, but could not adequately measure the volume nor evaluate the quality of the reservoir.

Magnetic Resonance logs were added to the typical logging program in an attempt to gain a better understanding of this complexity. The Bray-Smith bin permeability equation was used with the T2 (relaxation) response to accurately define permeability. The presence of hydrocarbon was clearly indicated by the T1 (polarization) response. These answers allowed completions to be targeted in the more productive parts of the Tesnus and enhanced the calculation of net pay. This paper summarizes the results of using these measurements to design completions in this difficult reservoir. This approach can be applied in many difficult evaluation situations.
Nonproductive Time Reduction Through a Deep-Rig Time Analysis: Case Study
Authors: Moazzeni Ali Reza , Nabaei Mohammad , Ghadami Saeed
Published: September 2011

Abstract As time goes by, increase in world energy demand forces oil and gas companies to drill deeper in order to produce more oil and gas for balancing world's offer and demand. This requires drilling layers with various characteristics and dealing with more drilling problems as drilling progresses. Reduction of drilling problems can help drillers to reduce their cost effectively. Rig time break down of more than 300 wells in one south west Iranian oil field has been analyzed to determine effective parameters on non-productive time amount. Results show that the most common drilling problems always have been experienced by drilling engineers are Equipment failure, stuck pipe and lost circulation. They expose huge expenses to the oil companies because of either drilling fluid supplement or subsequent drilling problems like fishing and side tracking. Next step was determination of new methods for reduction of lost rig times. Some new methods such as artificial neural network, genetic algorithm and curve fitting were used to predict occurrence of these phenomena for reducing or preventing them. Several factors while drilling will govern how severe mud loss and stuck pipe would occur. These actually make analytical modeling of lost circulation or pipesticking to somehow complicated. Hereby, employing artificial intelligence can be a leeway with proven capability and accuracy. In this research, operational parameters in Maroun oilfields are used for prediction of the mud loss severity along different sectors of this oilfield. Performed cross validations show fairly good compatibility with what happened in reality. Also artificial neural network was employed to predict stuck pipe position and stuck pipe severity before happening. as well results are well-matched with reality. Introduction Over several years oil industry is facing troubles associated with the stuck pipe and lost circulation. Differential pipe sticking is one of the stuck pipe mechanisms that have had a major impact on drilling efficiency and well costs1-3. These occurrences are common everywhere in the world and are estimated to cost the industry hundreds of millions of dollars annually4. In some areas, events related to differentially stuck pipe can be responsible for as much as 40% of the total well cost. Differential pipe sticking problems generally result in the well cost overruns and time overruns as a non-productive time in terms of loss of rig days either due to stopping of drilling operations or an attempt to free the stuck pipe. This huge loss is always accounted in the well budget cost as a contingency factor for the risks associated with the stuck pipe problems in the well planning and drilling performance approach.
Magnesium Peroxide Breaker for Filter Cake Removal
Authors: Mahapatra Shrikant K. , Kosztin Bela
Published: September 2011

Commonly used Drill-in Fluids (DIF) are typically comprised of starch, xanthan and sized calcium carbonate. Although, DIF is inherently less damaging than the conventional drilling mud, relatively impermeable filter cakes are still deposited on the borehole walls. The polymer in the mud provides cohesiveness and encapsulates the bridging solids (CaCO3). Consequently, the polymers in the cake retard the dissolving of the bridging particles and therefore, must be decomposed to allow a complete and even dissolution of the soluble solids in the filter cake. A common practice to minimize such damage is the application of acids (External Breaker) or strong oxidative breaker (Internal Breaker) system to dissolve filter cake solids and biopolymers.

Magnesium Peroxide is an internal breaker. It is a classified oxidizer which slowly decomposes to release oxygen. Since magnesium peroxide is a powdered solid, it becomes an integral part of the filter cake. Due to the extremely low solubility of Magnesium peroxides it remains stable for extended periods of time in alkaline environment and within the filter cake. The magnesium peroxide, when exposed to an acidic solution, it releases hydrogen peroxide which degrades the polysaccharide type polymers and open-up the external filter cake.

In an effort to evaluate the effect, laboratory experiment was carried out. Due to the wide range of possible mud system, a pragmatic range was selected for evaluation. A total of six different drill in fluid were formulated, based on practical application in the field. The laboratory experiment shows that magnesium peroxide influences the acid clean up. Subsequent field trial in three horizontal wells in South Oman field showed excellent stability of the mud and clean up after soaking in 15 % hydrochloric acid.
Quebrache Field: Evaluations to Date of this Natural CO2 Reservoir
Authors: Gachuz-Muro Heron , Sanchez-Bujanos Jose L. , Castro-Herrera Israel , Rodriguez-Pimentel Jose A.
Published: September 2011

In the search for oil and gas during the past century, other gases have been encountered. These gases had little or no economic value and areas known to contain them were avoided during drilling.

Deposits of CO2 rich gas (>50 %) are present worldwide but in limited areas – USA, mainly. Few studies of natural CO2 reservoirs are currently available to determine and analyze its accurate exploitation. CO2 concentrations ranging between 71 and 98 % have been discovered in the Northeast of Mexico. Preliminary evaluations (SPE-107445) of the available data for Quebrache field indicated potential gas reserves.

Complementary analyses to date have shown that on balance, the Quebrache field offers a significant opportunity for developing Enhanced Oil Recovery (EOR) projects. This new study divides the field into tree important areas. This paper presents: a) recent reservoirs discovered b) estimated reserves for all tree areas with CO2 sources (Central Area, Northern Area and Southern Area), c) efforts made to evaluate its potential d) opportunities to invest in and operate a world-class CO2 reservoir, etc. The Central Area reveals 2 important reservoirs. These reservoirs are relatively continuous and could produce and drain reserves during long period. Original Gas-In-Place (OGIP) volumes are likely conservative because in its calculation it is assumed a gas-water contact (there is contact apparent in the well logs). The Quebrache field would provide strategic value to CO2 injection programs.

The CO2 accumulations described in this paper could play a major role in recovering additional oil from fields in the North of Mexico. Thus, CO2 accumulations in the right place and at the right time may become production targets in the future.
Holistic Optimization Approach Improves Economic Viability of Bakken Shale Play
Authors: Ibrahim Hani , Gidh Yashodhan , Purwanto Arifin , Bits Smith
Published: September 2011

The Bakken Shale is one of the largest, unconventional crude oil plays in the United States covering as much as 25,000 sq miles in the Williston Basin. The formation underlies portions North Dakota and Montana and is found at depths ranging from 9000ft to 10,500ft. Reserve estimates vary but the United States Geological Survey (USGS) has calculated risked undiscovered resources of up to 4.3 billion barrels of recoverable oil and bbl/cu ft equivalent using current technology. At this time the field is being developed with single, dual and triple-leg horizontal wells with laterals extending 4500ft to 9500ft into the formation.

However, drilling activity in the area has fluctuated as a result of changing oil prices. Accordingly, reducing overall operation costs is essential to the economic feasibility of each drilling project. Because of the significant impact on drilling costs, the correct selection and utilization of drilling equipment including bits, drilling fluids, hydraulics and downhole tools is paramount. To optimize operations, a holistic approach was adopted to create a drilling "road map" utilizing several application software systems. These software tools enable engineers to envision the specific drilling environment and tool/BHA interaction before the bit goes in the hole.

A recent Bakken project included expert drill bit selection, rock mechanics analysis, shock studies, drilling fluids and hydraulics optimization. The directional well plan was optimized with wellbore simulation software. In order to circumvent deficient options prior to and during actual drilling operations, multiple scenarios are simulated using a collection of detailed geological and offset drilling information. These results were studied, analyzed and assessed as the optimum drilling solution prior to submitting them to the operator. Finally, the service provider monitored and implemented the recommended engineered solutions.

The initial results were encouraging: Drilling days on Well 1 were reduced by 30% which represents a cost savings of $572,000USD while achieving the drilling target and delivering a high-quality wellbore. Building on this initial success, second and third wells confirmed the value of holistic optimization saving the operator 13 days ($676,000USD) and 16 days ($832,000USD) of rig time respectively.
Downhole Safety Valve for Well-Intervention Operations: Design, Testing, and Successful Case History
Authors: Ehtesham A. , Reesing D. , Giles J.
Published: September 2011

As things progress each year in the oil industry, there is a much greater emphasis on safety. Live well-intervention operations are challenging because of inherent risks and require detailed risk analysis and appropriate mitigation, such as redundant safety devices. This paper presents details of the development, testing, and successful field deployment of a newly designed safety valve that can be used on coiled tubing (CT), jointed tubing (JT), and CT-JT hybrid string applications.

This safety valve, located at the junction of the CT and JT, is a key component of the CT-JT hybrid string. Once the CT is connected to the JT, the valve can be pressure actuated to close or open the flow path to the wellbore. This allows the hybrid string to be run in hole (RIH) and pulled out of hole (POOH) with complete wellbore-pressure control. Various methods can be used to activate the valve, such as using surface hand pumps, pressuring between blowout preventers (BOPs), or remotely with pressure differential downhole.

Double-flapper check valves have typically been part of a standard well-intervention bottomhole assembly (BHA). However, integrity of these valves is always in question after heavy pumping operations, especially with sand-laden fluids. This new safety valve incorporates a protective sleeve that keeps the flapper assembly covered and in pristine condition in its normally open position, helping to ensure a more reliable seal on closure. Chemical compatibility of elastomers, along with low- and high-pressure sealing reliability, are some of the challenges involved with conventional designs. Considering these limitations, the new safety valve offers a true metal-to-metal, non-elastomeric, spherical-to-spherical, flapper-closure mechanism with low- and high-pressure sealing capability based on ISO 10432/API 14A specifications. The flapper valve is designed and manufactured based on award-winning subsurface safety-valve technology.

The safety valve was virtually tested using computational fluid dynamics, followed by functional testing on a full-scale prototype. Validation testing for functional, pressure, and sealing capabilities was conducted at an API type test facility. The safety valve was subsequently deployed and successfully passed field-trial operations.
Experimental Investigation of Fracture Interaction between Natural Fractures and Hydraulic Fracture in Naturally Fractured Reservoirs
Authors: Zhou Jian , Xue Chengjin
Published: September 2011

The interaction between natural fractures and hydraulic fracture was observed in multiple naturally fractured blocks by a series of physical model tests. The effect of natural fractures and in-situ stress on fracture geometry was revealed. Three types of fracture geometry were observed due to a change of in-situ stress contrast. Besides, pressure profiles could also reflect different characters of propagating behaviour. Random small natural fractures could lead to high frequency of pressure fluctuating during fracture propagation. Also natural fractures with strong network could lead to more smooth pressure during injection. Hydraulic fracture tended to be a dominating fracture with random multiple branches at high differential horizontal stress. It tended to be partly vertical (one wring), planar fracture with branches at a lower difference of horizontal stresses. Random natural fractures could dominate fracture geometry alone in condition of extreme low in-situ stress difference. In present of random natural fractures, mini-fracturing is still reliable if fracture geometry is a partly vertical, dominating one (even one wing).
Reservoir Characterization through Automatic History Matching of Underbalanced Drilling (UBD) Data in a Horizontal Well
Authors: Wu Zhan , Suryanarayana P. V.
Published: September 2011

During under-balanced drilling (UBD) of a horizontal well, down-hole pressure and temperature, as well as surface rate and pressure data are acquired. Theoretically, estimation of reservoir permeability profile can be achieved by quantitative analysis of these data. However, in practice, not only is a fine-grid reservoir simulator required to simulate the drilling schedule change due to tripping, completions, workovers, increase of well length with drilling and fluid flow in reservoir, but also an effective inversion approach is needed to estimate the reservoir parameters. The problem of reservoir characterization using UBD data has been studied by several previous workers. At current state of the art, neither analytical models nor commercial reservoir simulators are completely suitable for modeling the coupled system of UBD and reservoir fluid flow.

In this paper, we focus on the development of an automatic history matching technique to interpret the measured oil rate and down-hole pressure data while drilling. Our contributions are three fold. Firstly, a two-phase 3D reservoir simulator was developed in which the UBD drilling process was coupled into the reservoir simulator. Next, the reservoir simulator is applied to simulate the entire drilling process from penetrating the pay-zone until the well is complete. Secondly, a least square method is applied to match the down-hole pressure and oil rate data. The inversion for a synthetic UBD data set and realistic UBD data are demonstrated on a multi-zoned reservoir model. The results show that permeability and initial reservoir pressure can be obtained by matching down-hole pressure or oil rate in a short time of exposure to the reservoir section. Finally, we offer the details for implementing the UBD process in the simulator and discuss the practical issues of the application of UBD data in reservoir characterization through this automatic history matching technique.
Simulation of Parameters Derived from Nuclear Magnetic Resonance Log Using Conventional Well Logs and Fuzzy Logic
Authors: Maximiano C.. , Carrasquilla A..
Published: September 2011

Nuclear Magnetic Resonance (NMR) technique is currently used in well logging to provide important informations so that the interpreter can analyze the physical properties of oil reservoirs. This tool provides informations, in a more effective way than the conventional logs on free and irreducible fluids, total and effective porosity, and permeability, which allows a better reservoir interpretation and the consequent hydrocarbon evaluation. One of the ways to make this is using artificial intelligence approaches as Genetic Algorithm, Fuzzy Logic, Neural Network, etc., to synthesize porosity and permeability parameters derived from NMR log, using as input only conventional logs of petroleum industry, such as natural gamma ray, spontaneous potential, caliper and resistivity. This process is justified because NMR log is currently expensive and, for this reason, it is not done at all wells and can not be obtained in cased holes, but provides physical characteristics of the reservoirs which are hardly obtained by other means, either through conventional geophysical logs or formation evaluation techniques. Initially, we developed an algorithm, using Fuzzy Logic Tool of MATLAB software, with log data of East Texas, aiming to see the influence of the number of membership functions in clustering. When three linguistic classes were selected, the results were not satisfactory because the synthetized logs showed a box form. Then, when we removed the middle linguistic class, an improvement was observed in the synthetized logs, however, still having a box pattern. Finally, using the ISODATA algorithm of MATLAB, a better fit with the real porosity and permeability curves was obtained, eliminating box shape and promoting a more careful division of clusters. In this form, we demonstrated the feasibility of the simulation of parameters of NMR log through Fuzzy Logic.
Peregrino: An Integrated Solution for Heavy Oil Production and Allocation
Authors: Beall R.. , Sheth K.. , Pessoa R.. , Olsen H..
Published: September 2011

An Integrated Solution Enabling Allocation of Heavy Oil in the Peregrino Field

The complexity of producing from a heavy oil reservoir is a challenge limited by both economics and available technology. Various methods exist for producing from heavy oil reservoirs, but in areas such as Latin America, cold production is used where electrical submersible pumps (ESPs) are employed to artificially lift the oil from the reservoir.

This paper highlights an integrated approach of using ESPs and downhole flowmeters in heavy oil production. It will focus on the validation and analysis of production performance from ESPs and the allocation performance of the downhole flowmeters used in multiple wells in Peregrino field, offshore Brazil to address huge variations in the wells’ behavior such as production rates and bottomhole pressure.

A test was commissioned to benchmark ESP and flowmeter functions when working in tandem. Three sizes of ESPs and flowmeters were tested over the flow range of 500stb/d and 22,000stb/d and up to 360cP in oil viscosity. The ESPs were operated from 2300 to 3600 rpm in the different viscosity fluids and used water data as a baseline to calculate the performance correction factors for each operating condition. The performance correction factor is incorporated into the development of software to predict the performance of each pump at a specific operating condition. Eventually, the data will be used to develop the ESPs’ monitoring tool.

In the downhole flowmeter test, new correction methods were employed to improve the measurement accuracies such as an iterative calculation of the discharge coefficient based on the measured fluid properties. Test results will help validate ESP performance and verify flowmeter allocation accuracies to meet ANP specifications. The lessons learned will be applied toward future field allocation application using downhole flowmeters in the Peregrino field.
Investigation on Variations in Wettability of Reservoir Rock Induced by CO2- Brine-rock Interactions
Authors: Zhu Zihan , Li Mingyuan , Lin Meiqin , Peng Bo , Sun Liang , Chen Long
Published: September 2011

Originally, the reservoir rock surface is hydrophilic at atmosphere pressure, because they are generally consisted of hydrophilic minerals, such as quartz, feldspar, calcite, dolomite and clay minerals. According to different hydrophilic magnitudes of different minerals and Cassie's law, the heterogeneous reservoir rock surface shows different hydrophilic magnitudes with different mineral compositions. Therefore, after CO2-brine-rock interactions, minerals dissolution and precipitation will change the mineral composition and the hydrophilic magnitude of the reservoir rock surface at the same time.

The present study implemented a CO2-brine-rock system in laboratory with elevated CO2 partial pressures at 323K and 343K. Surface properties of the reservoir rock (such as wettability, surface mineral composition, surface topography and surface element composition) were respectively determined by Wilhelmy plate, XRD, SEM and EDS method before and after CO2-brine-rock interactions. The contact angle results show with the increasing CO2 partial pressure, the contact angle of water on the reservoir rock surface increases at 323K, and decreases at 343K. SEM results show minerals dissolution and precipitation were both taken placed on the reservoir rock surface after CO2-brine-rock interactions. EDS results indicate carbonate minerals dissolution plays a dominate role at 343K, and secondary carbonate minerals precipitation mainly occur at 323K. There is a close relation between the contact angle variation of water and the element mole percentage variation on the reservoir rock surface. With the increasing O, Si, Al, Na or K mole percentage, the decreasing C or Fe mole percentage, the rock surface becomes more hydrophilic.
Safe and Energy-Efficient Method for the Initiation of an In-Situ Combustion
Authors: Grachev N. E. , Senin D. S.
Published: September 2011

Initiation of the in-situ combustion (ISC) may be accompanied by rapid increase of oxygen concentration in the production fluid. This may cause serious damage to the well equipment by corrosion or explosion.

The most common method for reducing the risk of incomplete oxygen consumption (and oxygen breakthroughs) is pre-heating of the bottomhole zone with the use of well steam treatment (WST) technology. It is possible to optimize the initiation of ISC process - to minimize amount of injected steam, to achieve maximum air injection rate in a fastest way and to ensure that no oxygen breakthroughs to producing wells will occur during initiation of the ISC process.

We propose a method for initiation of ISC based on the developed semi-analytical model. Our approach allows to calculate the increasing air injection rates, from initial value to maximum acceptable value. The method is applied to model prevention of oxygen breakthroughs and to provide fast and safe initiation of an the ISC. Two cases are considered: initiation of ISC in the reservoir with the initial constant temperature and initiation of ISC in the reservoir with the pre-heated zone around injector well. In addition, we develop a method of optimal initiation of ISC after WST that allows to spend a minimum amount of energy and to satisfy the conditions of effective, fast and safe initiation of ISC.

The CMG STARS reservoir simulator was used for testing the developed model. The results which were obtained in accordance with the developed semi-analytical model are in full agreement with numerical experiment.
Kadanwari Field: A Tight Gas Reservoir Study and a Successful Pilot Well Give New Life to an Exploited Field
Authors: Valzania S. , Kfoury M. , Grandis M. , Valdisturlo A. , Fanello G. , Guerra L. , Heikal S. , Kashif A. , Sultan A.
Published: September 2011

Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight.

The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post frac-job evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.
A Case Study of the History Matching of a Sector of the Norne Field Using the Ensemble Kalman Filter
Authors: Szklarz S. P. , Hanea R. G. , Peters E.
Published: September 2011

In the history matching process reservoir parameters are estimated so they can be further used in a simulator to reproduce the past behaviour of the reservoir. During the last two decades the methodology evolved from manual methods to computer assisted procedures which can handle larger amounts of data. Now, when the computational power has increased enough, it is possible to perform more complicated computations and use more advance methods and at the same time choose more realistic simulation models. In spite of that, the field cases which are chosen to history match, even if more realistic they often are still synthetic. Therefore, the history matching procedure has been applied as a real case study based on Norne Field located near the Norwegian coastline. The preliminary results and the experience of handling realistic dataset are shared in this paper. The Ensemble Kalman Filter, which is recently a very popular method, has been chosen to match the well production rates and bottom-hole pressures to the real observations acquired in the segment of the field. Within the numerical experiment, permeability and porosity were estimated. Obtained results are a basis for continuation and the further improvement of the history matching process of the Norne Field. In addition, the issues encountered during the study are discussed i.e. the treatment of the flow conditions on the segment boundary and construction of initial ensemble.
Use of Pressure-Rate Deconvolution to Estimate Connected Reservoir Drainage Volume in Naturally Fractured Unconventional Gas Reservoirs from Canadian Rockies Foothills
Authors: Chen Andrew , Jones Jack R.
Published: September 2011

A number of successful case studies are presented in this paper to demonstrate the use of the pressure-rate deconvolution approach to estimating drainage areas for wells completed in some of the naturally fractured tight gas reservoirs of the Canadian Rockies Foothills. This study covers the application of deconvolution to two key carbonate stratigraphical horizons in the area: the Triassic Baldonnel and the Permo-Carboniferous Taylor Flat formations. Our original application of pressure-rate deconvolution was to wells in a major Cretaceous-aged sandstone member, the Cadomin-Nikanassin horizon. This process and results of this original application wil be documented and presented in a separate publication (Jones and Chen, 2011). In these structural plays, the matrix rock properties controlling the gas storativity of these formations are low with porosity between 3% and 6%. Correspondingly matrix rock permeability is also low with values between 0.01 and 0.1 md. However, all of these formations have been thrusted, overturned and have been subjected to reverse faulting. These diagentic factors have created swarms of natural fractures which control flow rates and may define rock volumes connected to individual wells.

In each well, a pre-production short flow test for each is performed with the intent of ensuring acceptable flow rates and to scope facility design. At this stage of early development, initial gas in-place (IGIP) estimates are derived from geophysical mapping mainly with plans to calibrate this IGIP number through the application of gas material balance, rate-transient analysis and/or simple late-time rate decline.

In recent years, the pressure-rate deconvolution approach has been successfully applied to many of these reservoir pools. The rate history data is available in the early stage of production, which is integrated with pressure buildup data collected later in the production life of a well during annual or routine, relatively short shut-in periods. Application of deconvolution in this paper is aimed at detecting early signs of pseudo-steady state pool depletion and to estimate the connected drainage volume.

The case studies presented here compare the deconvolution drainage volumes with the estimates from volumetric IGIP, gas material balance, and rate-transient analysis. The procedures help calibrate and/or reconcile geoscience defined volumetric resource sizes, map remaining reserves and possible infill-drilling opportunities.
Underground Natural Gas Storage in the UK: Business Feasibility Case Study
Authors: Escobar Esther , Arteaga Gerardo , Kemp Alexander
Published: September 2011

Currently the United Kingdom has the lowest natural gas storage rate in Europe although this is set to increase. The UK Government is committed to an increase in gas storage infrastructure by facilitating its construction, through reforms to the planning and licensing regime. The Government considers that the key to security of supply lies with a regulatory framework that provides incentives for commercial storage and with liberalisation of the gas market in Europe.

However, there have been growing doubts from investors regarding the profitability of projects promoted by the UK for underground gas storage, leading to possible delays in some of the planned gas storage schemes that have been announced, thereby compromising the security of gas supply in the UK.

The purpose of this case study is to investigate and determine the economic feasibility of a gas storage project in a depleted gas reservoir in the UK. The study analyses economic considerations in a hypothetical depleted gas reservoir-based storage facility.

An economic valuation was carried out by means of seasonal values, also known as intrinsic values, using pairs of natural gas forward prices. Subsequently, a project cash flow, linking technical and economic variables, was built to compute the project's NPV and to perform stochastic optimisation and forecasting modelling. The research also involved a statistical analysis of the UK natural gas market from 1998 to 2009.

Project outcomes established that in order to achieve the profitability of the project, relatively high price spreads are required. The analysis of the UK market shows that adequate spreads have scarcely occurred in recent years. Companies may thus delay the development of gas storage facilities and the UK government may have to offer incentives to procure the desired results.
Evaluation of Three-Phase Relative Permeability Models for WAG Injection Using Water-Wet and Mixed-Wet Core Flood Experiments
Authors: Shahverdi H. , Sohrabi M. , Fatemi M. , Jamiolahmady M. , Irelan S. , Robertson G.
Published: September 2011

Three-phase flow occurs during many important processes in oil reservoirs including tertiary gas and water-alternating-gas (WAG) injection. Accurate estimation of three-phase relative permeability (kr) is required to describe and predict the behaviour of these multi-phase flow conditions. The current approach in the oil industry for simulation of WAG experiments is to use two-phase relative permeability data to generate three-phase kr values by using correlations (e.g. Stone1, Baker, etc) available in commercial reservoir simulators.

In this paper, we evaluate the performances of the existing three-phase relative permeability models against experimental data. Two sets of WAG experiments were carried out by performing core flood experiments on a water-wet and a mixed wet core using low IFT oil/gas fluids. The results show that choosing inappropriate three-phase kr model in simulation of the WAG experiments can lead to large errors in prediction of fluids production and pressure. The predictions made by the existing models can be very variable and various models can predict vastly different 3-phase kr values from the same 2-phase data. While some models perform better than others, all of the 3-phase kr models examined in this study fail to predict the continued production of oil after the breakthrough of the gas which is one of the features of gas and WAG injection experiments at low gas-oil IFT (interfacial tension). The resulted three phase relative permeability obtained from WAG experiments revealed strong cyclic hysteresis for oil, water and gas relative permeabilities in both water-wet and mixed-wet systems.

Our results highlight some serious shortcomings of the existing hysteresis models. Comparison of the kr hysteresis observed for water-wet and mixed-wet WAG experiments demonstrates significant differences between the results obtained for the two wettability conditions which demonstrates the impact of wettability on three-phase flow during cyclic injection of water and gas and the importance of performing these experiments under representative wettability of the reservoir.

The results clearly demonstrate the need for improved models and methodologies for obtaining three-phase kr and also kr hysteresis especially for WAG injection.
Estimating Facies Felds using the Ensemble Kalman Filter and Distance Functions–Applied to Shallow-Marine Environments
Authors: Lorentzen Rolf J. , Nævdal Geir , Shafieirad Ali
Published: September 2011

The ensemble Kalman Filter (EnKF) is one of the most promising tools for assisted history matching of reservoir models, and it has in particular proven to work well on cases where petrophysical properties are modeled using Gaussian random fields with variogram models. However, many operative oil and gas reservoirs have challenging complex geological structures. These structures typically have rapid spatial variations in the petrophysical properties (e.g., permeability and porosity). The consequence of applying the EnKF directly on such reservoirs is that the characteristics of the fields are lost, i.e., sharp gradients are smeared out.

In this paper we propose a method where distance functions are used to estimate an arbitrary number of facies types. A distance function is defined as the shortest distance between a given position in the field and the boundary separating facies types. The idea behind this approach is that distances have smooth properties, and the distribution of the ensemble in a given gridblock is therefore in agreement with the EnKF Gaussianity assumptions. The distances are then updated using the EnKF, and converted to petrophysical parameters when the reservoir simulator is run to the next assimilation time. One distance function is used for each facies type. The approach is flexible and simple, and possesses several advantages compared to other existing methods: There is no restrictions on the structure of the facies field to be estimated.The methodology is able to update variations in the petrophysical parameters within each facies type.The input for the method are facies realizations that can be generated with any preferred geostatistical tool.We ensure that the updated fields always are facies realizations.We ensure conditioning of the correct facies types at the well location, both initially and during the assimilation steps.The method does not involve complex modifications of the standard EnKF equations.

Additional improvements in the quality of the updated facies fields are obtained by proper handling of the distances close to the reservoir boundaries, and conditioning on specific statistical measures to better preserve prior information about the field properties.

We demonstrate the methodology on a field with shallow-marine environment characteristics. The conclusions from the example are that the history match is improved, uncertainty is reduced and the method always returns facies realizations with geological authenticity.
Validation of THAI Bitumen Recovery Using 3D Combustion Cell Results
Authors: Greaves M. , Dong L. L. , Rigby S. P.
Published: September 2011

Rigorous validation of a simulation model of the THAI –Toe-to-Heel Air ijection process has been performed using results obtained from a 3D combustion cell experiment on Athabasca Oil Sands. The numerical model includes a new kinetics formulation, based on the Athabasca thermal cracking kinetics scheme proposed by Phillips (1985). The kinetic model excludes low temperature oxidation, since THAI operates in a high temperature oxidation mode. Excellent agreement was obtained between the predicted and experimental oil production rate, and there was generally a good match obtained for other dynamic variables, including the residual coke profile, produced oxygen, and peak combustion temperature. The numerical model provides a fundamental platform for upscaling to field scale, that will enable fine scale details of the process to be captured.

Simulations were performed under dry in situ combustion conditions at the high air injection fluxes used in the experiment. Under these conditions, vertical-plane temperature profiles in the sandpack confirm that the combustion front is quasi-vertical and forward leaning in the direction of the heel of the horizontal producer well. The shape of the combustion front was predicted more accurately from horizontal-plane profiles, which showed that there was no oxygen in regions ahead of the combustion front. Oil displacement occurs mainly by gravity drainage, but pressure draw down in to the horizontal producer well below the Mobile Oil Zone (MOZ) is also significant. Various zones that develop during the in-situ combustion process include a ‘Steam Zone’, and this is located upstream of the Mobile Oil Zone (MOZ). All of the mobilized oil is produced from the MOZ, which comprises two regions. The first part contains oil produced by thermal cracking of the heavy residue and vaporized ‘lighter oil’. The main bulk of the oil produced in THAI comes from the second region of the MOZ, containing ‘banked’ original oil. The oil which is eventually produced is partially upgraded oil, due to the thermally upgraded and ‘lighter oil’ fractions mixing with the original oil when they enter the horizontal producer well.
Influence of Lumping and Equation of State Tuning Methods on the Sub-Salt Reservoirs Simulation
Authors: Mello S. F. , Ligero E. L. , Scanavini H. F. , Schiozer D. J
Published: September 2011

The Brazilian pre-salt oil reservoirs contain a considerable amount of methane, CO2 and volatile fractions under high pressure. Several authors suggest that the compositional reservoir simulation is fundamental for the description of their properties and prediction of oil production. Although this technique improves the quality of reservoir management, due to computational limitation, simplifications of fluid data are often recommended, affecting the quality of the compositional simulation. Petroleum reservoir behavior cannot be simulated in the most accurate way using present day computational resources. Simplifications such as lumping and tuning of equation of state (EOS) to describe mixtures have influence on the phase behavior. Fluid characterization becomes an important source of uncertainties in reservoir simulation because PVT data tuning is an inverse problem with multiple possible answers. The objective of this study was to show the impact of the description of the oil behavior under typical Brazilian sub-salt conditions considering oil production and computational effort. This was done through the study of EOS and comparison of the complete fluid with the lumped fluid descriptions. Since simplifications are adopted and PVT data-handling errors are introduced, it was necessary to detect and minimize them. The analysis of this study used comparisons of phase envelopes, MMP and reservoir simulations in a synthetic model. The studied model was based on the second model of SPE 10th comparative study, heterogeneous, using oil similar to that found in the Brazilian pre-salt, with 42° API, 3.55% molar CO2, and GOR 132.9 ft3 std/ft3. This work emphasizes the importance not only of experimental data quality but also shows the impact of the choice of regression and lumping methods. It also shows the importance of fluid modeling to obtain reliability in the reservoir simulation process.