bluuebunny/crossref_metadata_2025 huggingface dataset:
Propellant-Assisted Perforating in Tight-Gas Reservoirs: Wireline Formation Tests Show Successful Stimulation
Authors: van Galen M. W. , Cuthill D. A , Peterson G. L. , Bouwmeester D.
Published: July 2010

Propellant-assisted perforating systems are used to stimulate the near wellbore region and to alleviate the formation compaction damage from the perforating event. This method involves combining a perforating gun with a high pressure, gas generating propellant. Detonation of the perforating gun causes the propellant to deflagrate. The resulting combustion gas enters the newly created perforations. This breaks down the compacted region and extends a fracture network from the perforation tunnels. Wireline formation testing has demonstrated the capability of this perforating method to stimulate beyond the depth of drilling and cementing invasion, especially in tight-gas reservoirs.

The wireline formation testing system is often referred to as a mini drillstem test (DST). It is conveyed into the well on wireline and it uses a dual packer assembly to isolate the perforated interval. With the pump-out capability of the tool, multiple drawdown and buildup cycles are performed. Pressure transient analysis (PTA) is applied to the measured pressure data to evaluate near-wellbore reservoir characteristics.

Depending on the formation parameters, there are two extreme responses observed in these tests: a radial composite model; or a linear fracture model. The radial composite model represents a higher permeability region in the near-wellbore area, surrounded by a lower permeability outer region representing the formation matrix. The typical radius for the inner region is up to 3 m. The linear fracture model represents a small fracture into the formation, generally with a fracture half-length of 1 to 2 m. In reality often a combination of the two models is more representative. All responses show less resistance to flow in the near-wellbore area, representing a positive cleanup and stimulation. Modeling indicates that the propellant-assisted perforation systems are capable of penetrating beyond any induced damage. This is often not the case when using conventional perforation charges.

This study comprehends 50 wireline formation tests in tight-gas reservoirs. These tests are used to demonstrate the successful application of propellant-assisted perforating techniques and to illustrate the different pressure responses created by propellant-assisted perforating in the near-wellbore area. The results are also compared to pre-job propellant stimulation modeling software analysis.
Risk of Losing Oil Reserve by Gas-Cap Gas Production in Malaysian Thin Oil Rim Reservoirs
Authors: Razak Ezzam A. , Chan Keng Seng , Darman Nasir
Published: July 2010

For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, the art of optimizing the oil recovery is to keep the oil rim in continuous contact with the producing wells in the oil rim. Therefore, the management of gas-oil contact and water-oil contact movement is extremely critical. To achieve the maximum results, force balance between aquifer drive, gas cap expansion, and viscous withdrawal (production) shall be carefully studied for a given reservoir at various stages of the production life cycle.

In this paper, the risk of losing oil rim oil to the gas cap when the force balance is impaired by weakening gas cap energy due to gas production is illustrated. This condition can also be observed due to impaired water injection or the improper placement of water injection wells.

For thin oil rim reservoirs with significant oil reserve, the strategy of hydrocarbon exploitation should be producing the oil rim oil first and then blowing down the gas-cap later to maximize hydrocarbon recovery (Ref. 1). For this reason, most of the produced gas shall be re-injected to the reservoir to keep the proper force balance and to enhance the improved oil recovery (IOR) options such as infill wells, water injection and enhanced oil recovery. Model simulation studies can demonstrate that the IOR benefit can severely reduced by producing gas-cap gas. A correlation between IOR recovery factor and gas cap gas withdrawal volume, for a particular thin oil rim reservoir in Malaysia, is shown and proposed.
Zhao Dong Drilling—A History of Innovation to Enable Continuous Improvement and Optimum Performance
Authors: Lin Low Siew , Mellor Andrew , Hill Robert , Scott Randy
Published: July 2010

This paper is a case study which pinpoints the key drivers that have created and sustained high performing organization using a mixture of local and international resources. It will show how a small, innovative, and empowered drilling team can consistently deliver top quartile drilling performance.
Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results
Authors: Hemphill Terry , Duran William , Abousleiman Younane , Nguyen Vinh , Tran Minh , Hoang Son
Published: July 2010

In today's increasingly complex well designs, often the range in drilling fluid densities required to prevent hole collapse without fracturing the wellbore, i.e. the safe drilling window, is narrow. This is often the case for wells having high angles of deviation, and is of particular concern in extended-reach drilling (ERD) wells. With increasing step-outs, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true vertical depth (TVD) remains fairly constant. The net result can be that as horizontal departure lengths continue to increase, the drilling ECD violates the safe drilling window.

In a recent study presented to the industry, the effects of changes in the water phase salinity (WPS) of invert emulsion drilling fluids (IEF) were investigated as a function of rock shear failure for two very different shales: a deepwater West Africa shale and a more-competent Oklahoma shale. After a 3-hr exposure time, the changes in rock strength with different WPS levels were measured directly and results were qualitatively consistent for the two shales.

In this paper, the effect of changes in the WPS of IEF on the safe drilling window is demonstrated in an ERD drilling scenario. The modeled failure envelope is first examined using conventional elastic modeling. Poroelastic modeling is then used to show the effect of changes in the safe drilling window resulting from changes in pore pressure. As a further step, changes in the safe drilling window are next shown using porochemoelastic wellbore stability modeling, where the effects of invert emulsion drilling fluid chemistry coupled with changes in pore pressure are introduced. The results show that the safe drilling window can be changed with invert emulsion chemistry, and that there is much to be learned using more advanced poroelastic and porochemoelastic modeling techniques.
Wiremesh: A Novel Shale Fracturing Simulator
Authors: Xu Wenyue , Thiercelin Marc , Ganguly Utpal , Weng Xiaowei , Gu Hongren , Onda Hitoshi , Sun Jianchun , Le Calvez Joel
Published: July 2010

A mathematical model was constructed to better characterize and predict the growth of induced hydraulic fracture networks (HFN) in naturally fractured formations such as shale. The model represents the HFN developed during a hydraulic fracturing stimulation treatment by a growing elliptic volume of the stimulated formation. It consists of two perpendicular sets of vertical planar fractures with mechanical interactions among themselves and with injected fluid fully accounted for. The model is further constrained by the amount of fluids pumped into the formation. Based on this mathematical model, a semi-analytical simulator was developed for design and planning of hydraulic fracturing stimulation jobs. It is capable of predicting the growth of HFN (height, length, width)predicting proppant placement (all directions or dominant fracture only) and fracture conductivitysupporting variable pump schedules for fluid and proppantsupporting limited entry for slurry injectionsupporting multiple fluid typessupporting multiple proppant typesdegenerating to bi-wing fracture
Comparison between Bit Optimization Using Artificial Neural Network and Other Methods Base on Log Analysis Applied in Shadegan Oil Field
Authors: Bataee Mahmood , Edalatkhah Saeed , Ashna Rahman
Published: July 2010

Bit selection is one of the main challenges in drilling operations. Since the effect of drilling bit in total cost is inevitable, bit selection is introduced as a vital task in planning and designing new wells. Using bits with proper code improve bit drillability otherwise false code leads in readily damage and wear the bit. Bit selection is based on the history performance of similar bits from offset wells and also is done by different methods based on offset well logs. There are many parameters intervening in drilling bit selection. Therefore, developing a logical relationship among them to assist in proper bit selection is necessary and complicated though. In such a case, Artificial Neural Networks (ANNs) is proven to be helpful in recognizing complex connection between variables. Well logs expose different parameters of the formation; one of the most important parameter is hardness of the formation which can help us choosing proper bit. So we can have a comparison between two methods and check the answers with history drilling data of field.
Cementing Solutions for Corrosive Well Environments
Authors: Brandl A. , Cutler J. , Seholm A. , Sansil M. , Braun G.
Published: July 2010

Main factors which are responsible for the corrosion of the cement sheath in wells are determined based on lab tests and field analyses from a literature survey. A description of the chemistry, mineralogy, physical properties of API well cements and their mechanisms of corrosion in the presence of aggressive formation and injection fluids (such as magnesia or sulfate containing brines and CO2) are given. API cement hydration mainly produces Calcium-Silicate-Hydrate (C-S-H) phases, which are responsible for the strength, and portlandite "Ca(OH)2" which is basically a weak point within the cement matrix. Increasing permeability and portlandite content reduce strength and chemical resistance of set cement towards corrosive media. The addition of pozzolanic materials eliminates portlandite and allows lowering the water content in the cement system. Both effects can reduce the permeability and improve the mechanical properties of set cement. Cement specimens were prepared and exposed to CO2 loaded water at 300 °F and 3,000 psi for 6 months. Mechanical properties tests, microscopy, and quantitative CaCO3 analyses revealed significantly less corrosion and negative impacts for an API cement-pozzolan blend compared to a conventional API cement design at same density. Practical and economical concepts for improvements of the cement sheath with respect to cement slurry design, cementing process and the impact of factors such as temperature or cement admixtures are presented to mitigate cement corrosion.
Integrated Fractured Reservoir Characterization and Connectivity Study in the Cantarell Field
Authors: Bustos Arturo Vazquez , Eduardo Aguirre Cerda , Febres Anurfo , Antonio Villavicencio Pino
Published: July 2010

This paper presents a multidisciplinary and integrated approach that can be used for understanding the connectivity and conductivity in fractured reservoirs. A case study from a carbonate reservoir in the Cantarell field in Mexico will be used to illustrate this approach. The fracture model is constructed by using seismic volumetric curvature attribute. The characterization of 3D fracture model is made with borehole images and fracture seismic classification analysis, which help to identify the two main scales and three sets of fractures in the reservoir. Fracture networks made by long size fracture corridors are assumed to be imposed on the small size diffuse fracture density fields. The 3D fracture model by integrating reservoir engineering data, including mud losses during drilling, flow meter data, transient well test analysis and water production data, resulted in the calibration of effective hydraulic conductivity for each fracture type. Based on the 3D fracture model, the hierarchical modeling concept is taken into account in effective permeability tensor computation. Matrix and fracture parameters including fracture density, length, aperture and orientation are calibrated and used to generate 3D fracture- permeability models for the reservoirs. An effective permeability model on a directional fracture-set base is developed to quantify the reservoir conductivity. In this paper, case studies are used to illustrate applications of these technologies and their efficiency in interpreting unexpected field production features such as early breakthroughs and better understanding the controls on the oil recovery.
Parallel Simulations of Commercial-Scale Polymer Floods
Authors: Yuan Changli , Delshad Mojdeh , Wheeler Mary F.
Published: July 2010

Despite advances in numerical techniques and computer hardware, numerical modeling of commercial scale mechanistic polymer floods remains a challenge. A low order finite difference scheme defined on coarse grids (standard practice in oil industry), tends to smear the front and mask the benefit of polymer solutions whereas the more accurate finer grids require excessive computer run times. A comprehensive polymer module has been added to our in-house reservoir simulator to benefit from parallel capability, efficient algorithms, and accurate grids to make fine grid field-scale polymer flood simulations possible.

Polymer flooding is a mature technology to economically recover additional oil from medium to heavy oil reservoirs. Polymers are added to the water to improve the sweep efficiency in heterogeneous formations by reducing the water mobility (ratio of effective permeability to viscosity). Polymer is transported in the water phase by convection, diffusion, and dispersion and delayed by the adsorption of polymer on rock surfaces. Polymer properties include adsorption, permeability reduction, rheology, and inaccessible pore volume. Polymer solutions often exhibit non-Newtonian rheological behavior where the viscosity decreases as the shear rate increases. However, large hydrolyzed polyacrylamide polymers (HPAM) with molecular weights on the order of 20 million or greater exhibit shear thickening behavior where above certain critical shear rate the viscosity increases.

This paper describes a reservoir simulator with a comprehensive polymer property model and parallel capability on a cluster of PCs. Simulations of commercial scale polymer floods are performed using fine grid and multiple processors. The impacts of elongational polymer viscosity and near wellbore flux calculations are evaluated.
Application of Lithofacies Models to Characterize Unconventional Shale Gas Reservoirs and Identify Optimal Completion Intervals
Authors: Mitra Arijit , Warrington D. , Sommer A.
Published: July 2010

Unconventional shale gas reservoirs are economically viable hydrocarbon prospects, and their development has rapidly increased in North America. These reservoirs must be routinely drilled horizontally and hydraulically fracture stimulated to maximize production rates. Identification of the different chemostratigraphic units or lithofacies that make up these reservoirs is crucial for devising completion strategies because some lithofacies are more favorable to gas recovery due to their organic content and geomechanical characteristics.

Lithofacies are indicative of eustatic changes during deposition and are typical geo-markers related to the preservation and amount of accumulated Total Organic Carbon (TOC) for a given basin. Gas content is related to TOC and varies according to lithofacies. Based on the mineralogical and TOC content, some lithofacies are favorable for gas production (e.g., siliceous lithofacies) and the geomechanical properties of these lithofacies often possess low fracture gradients that are conducive to forming extensive fracture fairways for recovery of gas. Other lithofacies can be fracture barriers and zones of fracture propagation attenuation (e.g., carbonate lithofacies).

A shale gas facies expert system was developed with the goal of chemostratigraphically characterizing different shale plays and utilizing an integrated petrophysical reservoir evaluation approach to identify optimal completion intervals. This system can aid operators design selective completion strategies, which can potentially reduce fracturing expenses and optimize well productivity. The expert system incorporates a combination of density, neutron, acoustic, nuclear magnetic resonance and geochemical logging measurements. This system first characterizes the lithofacies based on their geochemical makeup and then flags the most favorable and unfavorable zones using a simple "stop-light" approach based on the petrophysical and geomechanical properties.

This paper presents facies models for the Barnett Shale, the Haynesville Shale, the Marcellus Shale, and the Woodford Shale applied to a case study well in each of these plays.
Impact of Reservoir Characteristics on Water Production in Enhanced Coalbed Methane Operations
Authors: Jamshidi M. , Jessen K.
Published: July 2010

Coalbed methane (CBM) formations deliver a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction.

The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface or by injecting gas. Disposal of the produced water is an environmental challenge and harmful impurities must be removed. Consequently, a reduction of the water production is desirable.

In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We use a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies significantly depending on the aquifer strength. We demonstrate that injection of CO2 and/or (N2) in some settings reduces the water handling problem substantially.

CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production and CO2 storage capacity provides valuable new guidelines for future operations.
Estimates of Fracture Lengths and Injection Profile in an Injection Well by History Matching Bottom Hole Pressures
Authors: Suri Ajay , Sharma Mukul M. , Peters Ekwere J.
Published: July 2010

An injection well model is presented that can be used to history match a field injector's bottom hole pressure (BHP) taking into account particle plugging due to injected solids, poro-elastic and thermo-elastic stresses, increase/decrease in injection induced fracture lengths, injector shut-ins / re-starts, changes in injection rates and average reservoir pressure. Estimates of fracture lengths and injection profile as a function of injection time are predicted for a field injector in a multi-layered reservoir.

The solids deposition is modeled accurately using filtration theory; the flow of the injection fluids is modeled using approximated composite zones (3 zones with uniform saturation and mobility) and the pressure at the wellbore is calculated using Gringarten's infinite conductivity fracture solution. The injection induced fracture lengths are calculated based on Perkins and Gonzalez fracture propagation model (1985) that accounts for the thermal and poro-elastic stresses. The model is a semi-analytical simulator that can predict injector performance through history matching an injectors’ daily record of injection rate and BHP. More reliable future estimates of injectivity, skin, fracture lengths in a multi-layered reservoir, front locations, and injection fluid profile can be obtained. Both short term pressure transients and long term pressure transients observed over several years of injection need to be history matched to capture effects that are important at both short and long time scales.

Finally an example field case study is presented where BHP and injectivity of an ongoing injection well is history matched for both a few short term injection time intervals and over a period of 3 years. It is shown that both the solids deposition and the opening/closing of the injected induced fractures need to be accounted to obtain a good history match. These processes controlled by the layer stresses and the water quality are the most important physical processes determining the injector's injectivity and injection profile.
A Novel Optimization Model for Analyzing Production Data
Authors: Cheng Kun , Wei Y. N. , Wu Wenyan , Holditch S. A.
Published: July 2010

The production data analysis is very important for petroleum industry since it serves as the fundamental step for reservoir development. In computer science, the self-adapting bionic optimization model is a state-of-the-art intelligent computation technique which can be used to analyze production data. In this paper we applied the self-adapting bionic optimization model to analyze production data. This method combines the heuristic approach, grey correlation analysis, and fuzzy clustering method in computer science to optimize the reservoir production plan.

To develop the method, we firstly perform grey correlation analysis to describe the initial correlation between production data parameters. By applying fuzzy clustering method, the production data are divided into different categories according to the degrees of their correlations. This heuristic information is used to construct the production data analysis model. Finally the best-optimized correlations among the various production data can be discovered. A simple example with related parameters is presented to show the algorithmic strategies. This example proved that our method is a flexible and cost-effective quantitative analysis method for production data analysis.

To evaluate this model, we selected 50 wells in some gas reservoirs from Xinjiang oilfield, China. The 50 wells have been developed for several years. Therefore, we have enough data on the 50 wells to be applied in this model. It is demonstrated that this model is useful in production data analysis.
Productivity Loss in Gas Wells Due to Salt Deposition
Authors: Le Duc , Mahadevan Jagannathan
Published: July 2010

Production of gas can result in drying of the near wellbore region due to gas expansion which causes evaporation and hence salt deposition. The deposition of salt leads to a reduction in porosity and permeability of the rock in the near wellbore which then leads to reduction in well productivity. The main objective of this work is to understand the role of salt deposition on well flow efficiency. Particularly, we investigate the effect of capillarity on the salt deposition process in reservoir.

We develop and solve the dimensionless conservation equations for solid salt saturation using numerical methods under radial flow conditions. The results of the calculations show that when the capillary effects are strong, the salt accumulates near the wellbore which leads to plugging and hence higher skin values. The salt saturation continues to evolve until a limiting value, in the rock pores, is reached. Higher values of the limiting saturation leads to a greater reduction in permeability and hence results in a larger skin value for the gas well. The flow efficiency of a gas well, calculated as a dimensionless ratio of the flow with and without skin, decreases continually and asymptotically approaches a constant value.

In a simulation for typical field case we find that the largest increase in skin factor and corresponding decrease in flow efficiency occurs in approximately the first 50 days after which the changes are slower. When connate water salt concentration is higher, the skin value is much higher and hence the well productivity is lower. Using the model developed in this study the decline of gas well productivity due salt deposition can be predicted and hence accurate timing of the well operations such as water wash can be made. Also, the modeling study can be used to select remediation strategies such as wettability alteration to reduce capillarity or application of inhibitors which can reduce the limiting salt saturation by preventing growth of salt crystals within the reservoir rock.
The Effect of Reservoir Heterogeneity on Gas Production From Hydrate Accumulations in the Permafrost
Authors: Reagan Matthew T. , Kowalsky Michael B. , Moridis George J. , Silpngarmlert Suntichai
Published: July 2010

The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to significant interest in the evaluation of their potential as an energy source. Large volumes of gas can be readily produced at high rates for long times from methane hydrate accumulations in the permafrost by means of depressurization-induced dissociation combined with conventional technologies and horizontal or vertical well configurations. Initial studies on the possibility of natural gas production from permafrost hydrates assumed homogeneity in intrinsic reservoir properties and in the initial condition of the hydrate-bearing layers (either due to the coarseness of the model or due to simplifications in the definition of the system). These results showed great promise for gas recovery from Class 1, 2, and 3 systems in the permafrost. This work examines the consequences of inevitable heterogeneity in intrinsic properties, such as in the porosity of the hydrate-bearing formation, or heterogeneity in the initial state of hydrate saturation. Heterogeneous configurations are generated through multiple methods: 1) through defining heterogeneous layers via existing well-log data, 2) through randomized initialization of reservoir properties and initial conditions, and 3) through the use of geostatistical methods to create heterogeneous fields that extrapolate from the limited data available from cores and well-log data. These extrapolations use available information and established geophysical methods to capture a range of deposit properties and hydrate configurations. The results show that some forms of heterogeneity, such as horizontal stratification, can assist in production of hydrate-derived gas. However, more heterogeneous structures can lead to complex physical behavior within the deposit and near the wellbore that may obstruct the flow of fluids to the well, necessitating revised production strategies. The need for fine discretization is crucial in all cases to capture dynamic behavior during production.
A New Management Strategy for Dead Oil Reservoirs With a Strong Aquifer
Authors: Prentt L. A. , Duarte A. G. , Charry W. M.
Published: July 2010

A reservoir management strategy is presented, based on a pressure-production behavior analysis, which was carried out using data from a Llanos Basin’s field in Colombia, applying the concept of Darcy’s Law and Babu-Odeh Equation for vertical- deviated and horizontal wells respectively. The analysis can be applied on dead oil reservoirs (Pres > Pb) providing a surveillance tool for making right decisions regarding the drawdown application as the well is produced, and thus maximizing the recovery factor.

The methodology allows the estimation of the dynamic evolution of skin factor, pressure drawdown and water saturation by well, which are related as well to variables such as water cut (Wcut) and Pwf for an easy handling and understanding of the field for geoscientists, reservoir and production engineers.

This methodology could be applied without the necessity to build a previous simulation model, but in this case a simulation model was carried out, in order to validate the input data, obtaining a good history match. As a result of this, the methodology and numerical simulation model are complementary themselves.

For this case, it was possible to define the proper/wrong application of drawdown increments that improve/reduce (mainly because of sanding) the productivity of vertical, deviated and horizontal wells for specific ranges of water cut.
Planning, Execution & Surveillance of Enhanced Oil Recovery Projects
Authors: Sinanan B. , Budri M.
Published: July 2010

Trinidad and Tobago’s onshore acreage has seen many stages of development. Currently, most onshore fields are well into their mature phase with the application of various forms of artificial lift being applied. Secondary recovery, through water- flooding, has been used in some fields with limited success whilst tertiary recovery methods, namely steam injection, have been more successful. These projects have been few and far between since there is a significant amount of acreage still to be considered for Enhanced Oil Recovery (EOR). An analysis of historical data has suggested that the application of modern day EOR screening, reservoir characterization tools and simulation would address some of the uncertainties that posed problems in the past.

An increasing number of mature oilfield acreage is being leased out by the state to private investors/operators. These entities must be prepared to efficiently exploit these mature blocks by optimizing current production operations, performing recompletions, in-fill drilling but most importantly by adding significant reserves through EOR projects. Many modern considerations within the feasibility stage through to health, safety and environment application must now be adhered to, for successful approvals from government regulators.

This paper provides a detailed outline of the different stages and processes that companies can follow or modify, to suit their reservoir management style, in pursuing successful EOR outcomes. This paper also addresses the importance of EOR screening, project management and surveillance techniques. Processes and recommendations developed from this work can be applied by any oilfield company who wishes to begin or expand their EOR project.
Experimental Investigation of Possibility of Replacing Oil-Based Muds with Environmentally Friendly Water-Based Glycol Muds in Maroon Oil Field
Authors: Saki Y. , Dinarvand N. , Habibnia B. , Shahbazi K.
Published: July 2010

Oil-based muds have been used widely in Iranian oil fields to drill pay zones and shaly formations. However, their applications have become more restricted because of high initial cost and prices of handling. The other important aspect is the environmental concerns that become more stringent in Iran. Therefore, an environmental friendly mud replacement having a good performance has become Iranian oil companies' demand.

Water-based glycol muds seem to be good alternatives for oil-based muds. These environmental friendly muds can inhibit shaly formations, lubricate drill stem, clean the hole, and deposit a thin and impermeable filter cake which reduce the risk of differential pipe sticking and damage, respectively. Moreover, initial and handling expenses are reduced, and these lead to the reduction in the overall costs of drilling the well.

In this study, rheological property of the water-based glycol mud was assessed and compared with the oil-based one. Cutting integrity test was performed in order to evaluate the performance of shale inhibition. This test was conducted on bottom hole samples of Kazhdumi, Daryan, and Asmari, three different problematic shaly formations of Maroon oil field. Formation damage caused by water-based glycol and oil- based muds was measured and compared.

It was found that the water-based mud has a comparable rheological property with respect to oil-based mud. The cuttings recovery percentage was within the excellent range. Formation damage caused by water- based glycol mud was more than oil-based mud. The results show that this mud system is a very good alternative to oil-based muds in Iranian oil fields.
Optimizing Oil Recovery and Carbon Dioxide Storage in Heavy Oil Reservoirs
Authors: Sobers L. , LaForce T. C. , Blunt M. J.
Published: July 2010

We study the design of enhanced oil recovery in heavy oil reservoirs combined with CO2 storage using field-scale reservoir simulation. We consider properties typical of fields offshore Trinidad and Tobago with oils whose density ranges between 940 and 1010 kg/m3 (9-18 degrees API). We first tune a three-parameter Peng-Robinson equation of state to match measured PVT data. We use experimental design to study the influence of oil properties, phase behavior and injection design on oil recovery and net CO2 storage. Carbon dioxide injection into heavy oil reservoirs enhances oil recovery through the mechanisms of crude viscosity reduction, oil swelling and immiscible gas drive. The process involves significant recycling of the injected CO2, but the reservoir is managed to keep as much of the injected CO2 as possible underground.
Trinidad Columbus Basin Petrophysics Field Study Part 2: Permeability and Water Saturation
Authors: Cross K. , Rose H. J. , Ali-Nandalal J. , Teelucksingh S.
Published: July 2010

A petrophysical refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed.

In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed. The core data set was expanded to include Co/Cw measurements on plugs from 2 wells to augment legacy data to investigate log-based water saturation methods.

New models were developed for permeability and water saturation and each of these models were calibrated against the core dataset. Permeability was re-evaluated with the new model being based on core-derived measurements and tuned to dynamic well test data to incorporate upscaling heterogeneities. Both log-based and core-based water saturation models were explored. The new core conductivity measurements provided support for the log-based method selected. Air-brine capillary pressure data have provided a key input to the development of a new saturation height function. The match between the new saturation height function water saturation and that derived from resistivity-based saturation is good, reinforcing its validity.
Effects of Fracture Properties on Numerical Simulation of a Naturally Fractured Reservoir
Authors: Noroozi M. M. , Moradi B. , Bashiri G.
Published: July 2010

Effects of Some of the fracture properties on numerical simulation of fractured reservoirs are usually not taken into consideration. Two important fracture properties, which are used in simulation, are fracture capillary pressure and fracture relative permeabilities. Engineers usually assume the first one to be zero and the second one to be a straight line without paying attention to their significant role in the simulation of fractured reservoirs. In addition, effects on these parameters on the behavior of fractured reservoir model when Dual Porosity Dual Permeability (DSDP) concept is used are not investigated yet. The present study investigates the effects of above mentioned properties through other fracture properties like fracture permeability and matrix- fracture transfer coefficient(shape factor) to analyze completely effects of the whole fracture characteristics on numerical simulation of a reservoir. The oil field under study is a highly fractured carbonate reservoir located in Southwest of Iran. This paper indicates when straight-line fracture relative permeabilities and zero fracture capillary pressure can be used in the simulation. Effect of reservoir heterogeneity was investigated on numerical simulation too. Sensitivity analysis also has been done to clearly indicate the behavior of the DSDP model by assuming /nonassuming zero fracture capillary pressure and straight line fracture relative permeabilities. Sensitivity analysis was done in three main production scenarios: natural depletion, water injection, gas injection. This sensitivity study will also show the magnitude of the error which simulation engineers are making if they use straight-line relative permeabilities and zero capillary pressure in the fractures.
Production Optimization in Trinidad and Tobago: Creating Sustainable Performance Through Collaboration
Authors: Samsundar K. , Chandass J. J. , Ramdial A. M.
Published: July 2010

The production optimization team in BP Trinidad and Tobago is a cross-functional team that is focused on optimizing production by safely maximizing the volume of gas available for our midstream customers. This paper will address the challenges faced in a high rate gas business that seeks to improve value is a fixed export regime. It will focus on the processes and tools that have been developed within BP Trinidad and Tobago and how it is being used to increase production.

To date the production optimization team has been able add approximately 5mboed each year through for the last four years through optimization of both the upstream and midstream activities and by managing the current available well stock. The team has also been able to implement new technology for optimizing production conditions called the Trinidad Field Optimizer. All of this is managed through the creation of a sustainable process that seeks to integrate the upstream operations, which includes drilling and new developments, with the midstream customers.

The journey of production optimization has taken four years to move from a place where each department worked in silos, focused on their own performance target, to one where the concept of integration is lived each day. During this time it has become very apparent that only through integration can maximum value be achieved once the right framework is created. Also technology plays a pivotal role in unlocking these hidden barrels. However with the myriad of new tools that is available in today's energy environment, special attention must be spent on selecting the right technology for your business.

This paper will demonstrate both the process and value that has been gained through the work of the production optimization team. It has facilitated integration of the company had has served to increase efficiency.
Applying Flow Zone Index Approach and Artificial Neural Networks Modeling Technique for Characterizing a Heterogeneous Carbonate Reservoir Using Dynamic Data: Case Study of an Iranian Reservoir
Authors: Shahvar Mohammad Bagher , Kharrat Riyaz , Matin Mehdi
Published: July 2010

Although static characterization of reservoirs is an inevitable part of any reservoir studies, the most robust models of the reservoirs can be obtained through integrating static and dynamic data. The following study which is done in a heterogeneous carbonate reservoir utilizes the capillary pressure and relative permeability data to verify the task of static rock typing and investigate the role of hydraulic units in capillary pressure and relative permeability modeling. For this purpose, at first, various rock typing techniques are applied to the field data to seek the best method which has the most consistency with capillary pressure curves. Using Desouky method which is based on hydraulic unit concept, Leverett J-function was then correlated with the normalized water saturation for each rock type to normalize and estimate capillary pressure curves. An excellent agreement exists between the measured data and calculated ones approving the applicability of Desouky method in heterogeneous carbonate reservoirs. Then, using porosity, permeability, wetting phase saturation and some functional links as input data, artificial neural networks (ANN) and specifically the back propagation feed forward neural network is applied as a new approach to predict relative permeability. However, instead of constructing the model for the entire depth of the well, discrete models are developed for each hydraulic unit individually. This idea is generated from the fact that each hydraulic unit has its own set of relative permeability curves and each set differs from one unit to another so the task of separating the models can reduce the discrepancies of the data and thus providing the more accurate synthetic models for predicting relative permeability. Results obtained from this model are compared with those of applying multiple regressions and also ANN method for the entire depth of the well. This comparison showed that the new approach introduced in this study can enhance relative permeability prediction considerably.
A New Precipitation Squeeze Alternative for Treating Harsh Barium Sulphate Scaling in a Highly Naturally Fractured North Sea Carbonate Reservoir
Authors: Todd M. J. , Lamont G. , Thornton A. R. , Gibb A. K. , Langvik M. , Sjursaether K.
Published: July 2010

Harsh barium sulphate scaling downhole presents a significant squeeze treatment challenge, particularly with providing and then maintaining scale inhibitor residual concentration for extended period at and above the high MIC demand. The control situation worsens considerably when faced with such a scenario in a high temperature, naturally fractured carbonate well. Conventional dispersive type squeezes have found favour here, however their placement and subsequent rapid return at high concentration can result in low squeeze lifetime, mainly due to poor retention of the inhibitor type. The paper details a solution to the inhibitor retention and high MIC demand challenges via development of a novel precipitation squeeze formulation which utilises the dispersive type scale inhibitor as its primary active.

The phase-separating ‘precipitation squeeze’ inhibitor formulation is designed to be deployed via conventional bullheaded squeeze into a high temperature, naturally fractured carbonate well environment. The material will thermally activate causing phase separation and enhanced retention of the inhibitor as its calcium salt. Since the active inhibitor is highly tolerant to calcium, it will return into solution with greater facility than conventional precipitation squeeze analogues, leading to elevated levels of scale inhibitor in solution for extended periods compared to standard chemistries in the same carbonate environment.

Simulated carbonate field coreflood tests indicated a 3-4 time squeeze lifetime extension was achievable using this technology, and formation damage assessments indicate no identifiable damage to the core material or fluid throughput. The material is now developed for bulk manufacture and is now in the field awaiting first pilot squeeze deployment at the time of writing this abstract.

This novel alternative squeeze treatment shows significant increase in achievable squeeze lifetime compared to existing scale inhibitor chemistries for squeeze deployment in harsh barium sulphate scaling carbonate field deployments. Benefits are logistical, environmental and economic when deploying this technology.
First Matrix Stimulation of Producer Wells in Sudan Delivers Outstanding Results
Authors: Shaheen Tarek , Ghazi Hassen Ben , Al Abdalla Fahmi , Izat Ali M.
Published: July 2010

After producing for more than nine (9) years, many wells in Sudan are suffering from lower production rate and increase in the skin value due to formation (Sand Stone) damage. Only re-perforation technique was used to mitigate formation damage problems; however, the results were not satisfactory.

Considered the first time in the history of oil production in Sudan, Some of the idle producer wells in Greater Nile Petroleum Operating Company (GNPOC) operations fields were selected to treat their formation damage problems and to start the first Matrix Stimulation Engineering treatment.

The results were outstanding where the oil production rate went up in the well TS-21 from 23 bopd to 1360 bopd. The well is still sustaining the high production rate after one year of treatment. The great success encouraged the implementation of the Matrix Stimulation treatment in different fields like Simber West where the results of the well SW-1 reached from 10 bopd to 900 bopd.

This paper discusses the methods used in identifying the Matrix Stimulation candidates and the innovative solution including the lab tests and the chemical work done in order to determine the best fit for purpose chemical treatment to bring the wells back to production and optimize the production trend in the field of Toma South and Simber West. It describes the Matrix Stimulation of the well TomaSouth-21 as an example. Furthermore, it describes the entire lesson learnt from the execution and operation phase

Last but not least, it shares the outstanding results and the way forward for the Matrix Stimulation business in Sudan. It gives a good reference and database for the stimulation treatment in Sudan since this paper is the first one to be written regarding Matrix Stimulation treatment in Sudan.
Successful Applications of Expandable Sand Screen in Persian Oil Fields, Part 1
Authors: Salehi-Moorkani Reza , Abbas Safian Gholam , Mirzaei-Paiaman Abouzar
Published: July 2010

In some Iranian oil fields hydrocarbon recovery is mainly from sandstone reservoirs and sand production is a major problem in these fields. Main reason of sand production in these reservoirs is due to unconsolidated sandstone layers. The common method to decrease this problem is achieved by installing mechanical sand control systems. Previously, some techniques of sand control have been used in Iranian oil fields, such as gravel packing, slotted liner and chemical consolidation by resin. The results which have been obtained through these methods are not remarkably good enough in some cases.

Expandable sand screen (ESS) is a new technique in sand control that can result in lower skin and consequently improves reservoir inflow performance. Field tests in various conditions have shown very satisfactory results in both open and cased hole applications. This paper will provide a brief overview of ESS and its advantages and will explains some of the concerns deal with ESS well completion. It provides details of well production results before and after installation of ESS. It also suggests that the use of ESS as an alternative to conventional sand control methods in Iran oil fields is preferable specially in cased hole completed wells.