bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Production Data for 2007/2008 Mallik Gas Hydrate Production Tests in Canada
Authors: Kurihara Masanori , Sato Akihiko , Funatsu Kunihiro , Ouchi Hisanao , Yamamoto Koji , Numasawa Masaaki , Ebinuma Takao , Narita Hideo , Masuda Yoshihiro , Dallimore Scott R. , Wright Fred , Ashford Douglas
Published: July 2010

The methane hydrate (MH) production tests were conducted using the depressurization method in the JOGMEC/NRCan/Aurora Mallik production program in April 2007 and in March 2008. In addition to attaining the first and the only successful methane gas production to the surface from a MH reservoir by depressurization in the world, various data such as wellhead/bottomhole pressure, temperature, gas and water flow rates and the temperature along the casing measured by Distributed Temperature Sensing (DTS) systems were acquired during these tests. The flow rates of gas and water from the reservoir sand face were then estimated by the comprehensive analysis of these data. This paper clarifies the details of the estimation of gas and water flow rates based on these data, for the first time after the 2008 winter test.

In 2007, a certain amount of gas and water were produced from a 12 m perforation interval in one of the major MH reservoirs at the Mallik site in Canada, by reducing the bottomhole pressure down to about 7 MPa. However, because of the irregular (on-off) pumping operations due probably to the excessive sand production, the produced gas was not directly delivered to the surface via the tubing, but was accumulated at the top of the casing. Hence, the gas production rate was calculated based on the continuously monitored bottomhole and casing head pressure. Since the produced water was injected into the aquifer located below the MH reservoir, it was impossible to directly measure the water pumping rate. The pumping rate and water production rates were accurately estimated by matching the bottomhole temperature through the numerical simulation using a wellbore model.

In 2008, much larger and longer gas production was accomplished with a stepwise reduction of the bottomhole pressure down to about 4.5 MPa, preventing sands from flowing into the wellbore by the screen. In this test, both the gas and water were delivered to the surface, which enables the estimation of the gas and water flow rates from the reservoir sand face as well as liquid level in casing based on the monitored parameters.

Investigating the production performances thus estimated, it was inferred what really happened in the reservoir during the tests. These insights must be beneficial for future exploration and development planning for MH resources.
Modeling Hydraulic Fracturing Induced Fracture Networks in Shale Gas Reservoirs as a Dual Porosity System
Authors: Du Changan M. , Zhang Xu , Zhan Lang , Gu Hongren , Hay Brad , Tushingham Keith , Ma Y. Zee
Published: July 2010

Shale gas production from organic rich shale formations is one of the most rapidly expanding areas in oil and gas exploration and production today. Because of extremely low permeability and low porosity, long horizontal wells in conjunction with multi-staged massive hydraulic fracturing treatments (HFT) are required to bring economic productions from shale gas reservoirs. It has been recognized that extensive fracture networks with massive contact surface areas are necessary to support economic productions from these reservoirs. Existing natural fractures observed from borehole images (mostly mineral-filled) and the low contrast of minimum and maximum horizontal stresses are some of the key factors in creation of the post-HFT network fracture system in many shale gas reservoirs.

Currently, comprehensive design tools for hydraulic fracturing treatments of shale gas reservoirs appear not available. These tools should have the capabilities to incorporate stress field, natural fractures and lithology heterogeneity of the reservoirs and model complicated fracture networks in shale gas reservoirs. However, microseismic mapping has been widely used to monitor hydraulic fracturing job responses, to help control job execution processes, and to evaluate stimulation results. Microseismic responses reflect the collective effects of the reservoir characteristics and hydraulic fracturing treatments, and can be indicative for the productivity of the post-HFT reservoirs.

This study presents a practical methodology to model hydraulic fracturing induced fracture networks in shale gas reservoirs as a dual porosity system. This approach decouples complex reservoir characteristics and geomechanical factors from production response. Microseismic responses are used to delineate stimulated volumes from a HFT. Microseismic events and/or natural fracture intensity, along with HFT data and production history-matching analysis, provide calibration for HFT fracture intensity. The calibrated post-HFT fracture network is crucial for production prediction.
Impact of Oil-Water Relative Permeability Curves on SAGD Behaviour
Authors: Lei Qiaohui , Wang Jacky , Gates Ian D.
Published: July 2010

Today, heavy oil and oil sands are starting to play a more important role. To manage and develop these resources, especially for thermal recovery processes, numerical modeling is often used to design the operating and well placement strategies. Relative permeability curves are one of the most important parameters for modelling these systems. This is especially important in systems where the saturation of each phase changes over a wide range as is the case in steam-based recovery processes such as Steam-Assisted Gravity Drainage (SAGD). Initially, before SAGD, the pore space of the oil sands reservoir is mainly occupied by bitumen with oil saturation typically between 80 and 90%. After steam is injected into the reservoir, the oil is heated and mobilized and drains under gravity and is replaced by first steam condensate and then, as the chamber propagates further into the reservoir, steam and solution gas. This means that the reservoir undergoes a series of large changes in phase saturations as the recovery process evolves in the reservoir. Thus, the interactions of the phases and their flow characteristics, that is, the relative permeability curves, are an essential component of the physics of SAGD. However, for modelling SAGD, due to limited relative permeability curve data, it is often adopted from analogs or previously history-matched curves. Given the heterogeneity of oil sands reservoirs, careless adoption of relative permeability curves will lead to serious risk of unexpected performance. The objective of this study is to investigate the impact of the endpoints of the oil-water relative permeability curves on SAGD performance by using numerical reservoir simulation. The results reveal that SAGD performance is sensitive to the values of the endpoints of the oil-water relative permeability curves. Given the range of variability of the results, it is recommended that relative permeability uncertainty analysis is always done during the simulation assessment of a targeted oil sands resource. Also, it is recommended that curves are obtained from multiple core samples of the target reservoir to reduce uncertainty and to assess the degree of heterogeneity of the endpoints.
Using Drilling and Logging Data for Developing 1D Mechanical Earth Model for a Mature Oil Field to Predict and Mitigate Wellbore Stability Challenges
Authors: Afsari M. , Amani M. , Razmgir S. M. , Karimi H. , Yousefi S.
Published: July 2010

Drilling through subjected mature offshore oil field is made more challenging by problems arising from wellbore instability, mud losses, excessive cutting, tight hole, stuck pipes and kick/flow zones for last few years. These problematic layers have caused quite a significant NPT (non productive time) during drilling.

For better understanding of factors causing wellbore instability problem and to predict mud weight window to be used for future wells, construction of mechanical earth model (MEM) was essential.

Mechanical Earth Model (MEM) is a numerical representation of the state of stress and rock mechanical properties for a specific stratigraphic section in a field or basin2.

In this study main drilling problems for each drilling interval in this field were described afterward different stages for construction an 1D Mechanical Earth Model (MEM) for the field was established. It was then demonstrated that how 1D MEM could be used to predict and prevent the common instability problems encountered during drilling.

For making MEM different sources of data including, drilling data, formation evaluation data, well testing, etc were used.

After making MEM for the field, safe and intact mud weight window was determined and according to that, suggestions for optimum mud weight for stable borehole on each interval was made.

MEM for this field can now be used to predict not only the safe mud weight window and possible drilling hazards, but can also be used for studies like reservoir compaction, sand production, and perforation stability and so on.
Ensuring Production in the Malaysian F6 Field Using Field Monitoring and Geomechanical Forecasting
Authors: Davison J. M. , Ita J. , Hofmann R. A. , Seli P. , Ong P.
Published: July 2010

The F6 field is one of many high porosity carbonate buildups developed in offshore Sarawak, Malaysia. With maximum porosities in excess of 30%, the reservoir experiences pore collapse during depletion. As a result, the predicted reservoir compaction and surface subsidence can be in the order of 25 ft or more. This poses a significant risk in terms of the platform subsiding into the wave-base, requiring shut in of production and prompting costly "jacking up" of the platform. To mitigate the risks it is recommended to build a field-wide 3D geomechanical model, constrained by available compaction and subsidence measurements, which are used to forecast future platform movement to end of field life.

The F6 field finite element geomechanical model was constructed from the 3D static structural model and populated with the calculated in-situ stresses and pore pressure distribution in the field from the reservoir simulations. The rock properties assigned in the model were derived from both log data and numerous core tests, which also defined their deformation and failure behaviour.

The F6 field has an on-going monitoring program, including compaction logging data in the reservoir, GPS data on the platform (both lateral and vertical movements), and sonar data for the platform height above sea level. Intermittent data gathered includes sonar seabed surveys of the subsidence bowl. This paper describes the data collected and how it is used to constrain the 3D finite-element geomechanical model constructed of the F6 field. The key findings of this study include; firstly, the importance of hard data in terms of reservoir compaction (compaction logging) and how this is translated through the overburden to surface subsidence (GPS measurements). Secondly, the importance of an accurate pre-production baseline for the monitoring program; it is relatively easy to match the rate of subsidence predicted from the model with the monitoring data collected after production start-up, however, the lack of pre-production data can lead to significant differences in the predicted absolute subsidence at end of field life.

The results of this study show the importance and value of geomechanical modeling constrained by historical observations from a field monitoring program and the necessity to have it included as part of the field development plan prior to start of production. Use of this data with geomechanical forecasting is now a significant component of production assurance for the asset and has lead to plans to increase coverage and frequency of data gathering over these highly compactable fields.
Building a Precise Mechanical Earth Model and its Application in Drilling Operation Optimization: A Case Study of Asmari Formation in Mansuri Oil Field.
Authors: Perchikolaee Razi S. , Shadizadeh S. R. , Shahryar K. , Kazemzadeh E.
Published: July 2010

Asmari formation in Mansuri oil field is a complex geological environment. Variation in proportion of different lithologies (sandstone, limestone, and dolomite) in this formation poses serious challenges to drilling and production management, and makes it difficult to evaluate lithological and geomechanical characteristics of reservoir formation.

Wellbore instability and formation damage could substantially decrease drilling and production efficiency. Drilling of Asmari formation is almost always accompanied with mud loss causing damage to the reservoir formation. With developing a consistent mechanical earth model, an appropriate mud weight window is suggested based on formation strength and induced stress along the wellbore. Choosing an optimum mud weight would prevent fracturing the reservoir and losing mud into formation. Hence, drilling time and production rate of Asmari formation would improve considerably.

In this paper, laboratory testing on cores such as triaxial compressive test and ultrasonic test under confining pressure of reservoir provides experimental data to establish precise correlation between compressional and shear velocity and calibrate dynamic elastic properties resulting from sonic and density log. In addition, static elastic properties and mud logging data is used to assess induced stresses due to drilling of the formation. As a result, an accurate geomechanical model is constructed in minimum error since a complete set of data required to perform a proper evaluation is available. In addition, numerical modeling as well as analytical one is employed to analyze stresses and strains around the wellbore, especially in complex, heterogeneous areas.

Suggested mechanical earth model helps petroleum engineers evaluate geomechanical characteristics of reservoir formation in spite of its natural heterogeneity, make field development and well construction decisions accurately, and overcome the challenges of this complex area throughout the life of the field.
The Design of Casing Used in Salt Layer in Gulf of Laizhou-China
Authors: Li Zhonghui , Lou Yishan , Zhang Chunyang , Zhu Liang , Xing Xuesong
Published: July 2010

Drilling through salt layer is one of the great technological problems; many operational problems such as stuck pipes and casing collapse have been reported by the industry when drilling through those salt layers owing to the characteristic of salt layers. In Gulf of Laizhou-china, wells have been drilled through thick salt layer in the shahejie formation, the lack of reliable ways to predict salt behavior led to very high costs and even loss of wells.

In this paper we present a methodology for casing evaluation in the salt layers. Based on the experimental results of the multistage loading creep for salt layer, the creep constitutive model and creep parameters is given. Consider the geologic condition of the salt layer, Do the numerical calculation of the creep pressure around the casing by FLAC3D code. And evaluated the casing rationality used in the salt layer according to the time-histories curve of the creep pressure and the steel grade, wall thickness, strength of the casing. The results obtained by numerical simulations were used to select the rational casing used in the salt layer. The conclusion is that under the force of the heterogenetic Earth stress, the strength of the casing used in the salt layer in the shahejie formation should select steel grade is N80, diameter is 244.5mm, and wall thickness is 11.99mm. As a result, casing collapse was avoided and drilling costs reduced.
Static and Dynamic Testing of Silicate Scale Inhibitors
Authors: Arensdorf Joseph , Hoster David , McDougall Don , Yuan Mingdong
Published: July 2010

Alkaline surfactant polymer (ASP) floods in sandstone reservoirs are associated with silicate scaling of production wells. Silicate scaling has been a significant problem in ASP-flooded fields in China (e.g., Daqing field) and Canada. This paper describes the results of both static and dynamic testing that reproduced the field conditions in a typical oil production well in a field under ASP flood. The tests were used to screen chemical inhibitors for the prevention of magnesium silicate scaling. Carbonate and silicate were allowed to scale concurrently in both tests. The static test was used to screen inhibitors, and the best performers were tested dynamically. The static and dynamic tests correlated well in terms of individual inhibitor results. In the static test, silicate slowly forms from the beginning of the test and calcium carbonate forms about two hours into the test. In the dynamic test, calcium carbonate forms very slowly while silicate scale forms more quickly and dominates. It is interesting to note that none of the chemicals tested acted as a threshold inhibitor and prevented scaling at low doses. Rather, the inhibitors tended to delay scaling. Significant delay of scaling required doses of 50 to 100 ppm (as active). This effect was observed both in static tests and dynamic tests. Although none of the products tested acted as threshold inhibitors, the best inhibitors could still be effective in the oilfield if silicate scaling can be delayed long enough so that fluids are moved out of the well before significantly depositing on surfaces downhole.
Coalbed Methane Cementing Best Practices - Indian Case History
Authors: Mohammad Haidher Syed , Shaikh Shahnawaz
Published: July 2010

Cement is placed as a sheath across coal seams in coalbed methane wells primarily for hydraulic isolation and to support the casing. Designing a cement job for coal seam wells requires contemplating factors beyond those considered in cementing conventional oil & gas wells.

Cement invasion into coal seams, losses during jobs, annulus pack off and low fracture gradient are the challenges generally encountered during cementing these wells. The low formation temperature also exacerbates the challenges as the cement must set within drilling schedule time constraints. Predicting the bottom hole circulating temperature during cementation is also a challenge because many such wells are drilled with air. Finally, most coal wells will be fractured and proppant placed for production enhancement. Cement invasion or improper cement sheath will hinder fracture performance.

Based on a seven-year study, pumping lower-density slurries does not completely prevent cement invasion but does affect the cement quality behind the casing. Achieving successful cement jobs in these wells requires special designs and techniques. The requirements include not only extensive testing in the lab, but also special placement techniques and cement systems designed to accommodate a low fracture gradient and to avoid cement invasion into these soft seams.

This paper will share case histories and best practices developed from seven years of experience in designing and placing cement successfully in coalbed methane wells in India. These case histories will include cement design considerations, lab testing procedures, special placement techniques and cement system choices.
Transient Behavior of Horizontal Wells with Inflow Control Devices for Inflow Profile Modification
Authors: Poe B. D. , Erkal A.
Published: July 2010

This paper presents the results of a study of the transient performance of a horizontal well that has been completed using Inflow Control Devices (ICD's) to modify the inflow profile along the wellbore to minimize the risk of premature gas or water breakthrough into the well. A realistic pressure and rate-transient design and interpretation computational model was developed and utilized in this study. The mathematical model has been used to evaluate the transient performance of a horizontal wellbore in single and dual porosity reservoirs.

The horizontal well model utilized in this paper considers the wellbore to be finite-conductivity and assumes that the well has been completed using ICD's to control the inflow rates of fluids along the wellbore. The ICD's may be installed in selectively completed intervals of the wellbore of varying lengths and number, including variation in the number and sizes of nozzles and perforations in each of the completed intervals. A wellbore outflow production systems analysis was also included in the model in order to design or evaluate the performance of a horizontal well using various lengths, grades, and weights of production tubular goods, and for varying surface operating conditions.
A Case Study: Profiling Gas Production in the Tubing/Casing Annulus, Using Noise/Temperature Logging Techniques
Authors: Molenaar M. M. , Cowan B. M. , Fidan E. , Cuthill D. A.
Published: July 2010

To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/casing annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs.

Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile.

Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/casing annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe.

In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator.
Effect of Fracture and Flow Orientation on Two-Phase Flow in an Oil-Wet Fracture: Relative Permeability Curves and Flow Structures
Authors: Shad Saeed , Maini Brij B. , Gates Ian D.
Published: July 2010

Naturally fractured reservoirs contain about 25-30% of the world supply of oil. In these reservoirs, fractures are the dominant flow path. Therefore, a good understanding of transfer parameters such as relative permeability as well as flow regimes occurring in a fracture plays an important role in developing and improving oil production from such complex systems. However, in contrast with gas-liquid flow in a single fracture, the flow of heavy oil and water has received less attention. In this research, a Hele-Shaw apparatus was built to study the flow of water in presence of heavy oil and display different flow patterns under different flow rates and analyze the effect of fracture orientations on relative permeability curves as well as flow regimes. The phase flow rates versus phase saturation results were converted to experimental relative permeability curves. The results of the experiments demonstrate that, depending on fracture and flow orientation, there could be a significant interference between the phases flowing through the fracture. In contrast with other studies, the results also reveal that both phases can flow in both continuous and discontinuous forms. The relative permeability curves show that the oil-water relative permeability not only depends on fluid saturations and flow patterns but also fracture orientation.
Scale Prediction for Oil and Gas Production
Authors: Kan Amy T. , Tomson Mason B.
Published: July 2010

Scale prevention is important to ensure continuous production from existing reserves that produce brine. Wells could be abandoned prematurely due to poor management of scale and corrosion. The objective of this paper is to present an overview of scale prediction and control and the current research at Rice University to solve these problems. In this paper, the challenges of scale prediction at high temperature, pressure, and TDS are reviewed. An accurate model to predict pH, scale indices, density, and inhibitor needs at these conditions are discussed. First, the various scale types found in oil and gas production and the condition under which they form are discussed. Secondly, the relationship of pH, alkalinity, organic acids, carbonates and CO2 distribution is discussed. Thirdly, the temperature, pressure, TDS dependence of the thermodynamic equilibrium constants and activity coefficients is discussed. Lastly, the accuracy of a scale prediction program and its application is discussed. Based on a simple propagation of error estimation, the overall estimated error for calcite SI is ± 0.1. The program has been validated with literature solubility data for 6 minerals, pH data at 25 and 60 °C, and density of high TDS solutions and up to 12.7 lb/gal weighting fluid.
Enhanced Heavy Oil Recovery from Fractured Vuggy Carbonated Reservoir of Tahe Oilfield with N2/CO2 Gas Mixture
Authors: Zhao R. B. , Ke W. Q. , Wu Y. H. , Zhao H. Y. , Yue X. A.
Published: July 2010

Oil production in fractured vuggy carbonate reservoir has unpredicted behaviors due to complex vug connectivity, variation of oil-water interface, and oil-water multiphase flow. Early water breakthrough and rapid increased of water cut as well as decreased of productivity are often encountered in this kind of reservoir. Experiments were conducted in vug-pore artificial cores with the size of 4.5 × 4.5 × 30 cm to study the influence of viscosity and different inclination angle on the oil recovery (OR). The influence of N2 and CO2 on the relative location of the water-oil/gas-water interface were compared. These results indicate that OR increases with the decrease of oil viscosity but not always with increase of inclination angle. Under CO2 conditions, however, influence of inclination angle on OR becomes more sensitive and gravity separation becomes more important factor at higher pressures.

Stainless steel tube with inner diameter (ID) of 1 mm was used to simulate the fracture. Time for CO2 and N2 gas cap formation are different as soon as the fracture width decreases to 1mm. For N2, the time increases with increase of pressure, and takes more than 50 hours as the pressure approaches to 4 MPa. While for CO2, however, a reverse behavior is observed and the time decreases to several seconds when pressure reaches to 8 MPa.

For vug carbonated reservoir with vertical connection of pore or fracture, CO2 can efficiently change the location of oil-water interface especially at smaller connecting space and produce much more oil. The N2 gas cap can maintain the high pressure to production layer due to its lower solubility both in oil and water.

Hence, great performance can be expected in the filed performance by injection of N2/CO2 gas mixture because of gas cap formation which attributes to pressure build-up and alteration of water-oil location by N2/CO2 injection.
Water Management vs. Water Control: Profitability, Not Cost, Driving the Paradigm Change
Authors: Anthony E. P. , Mohan A.
Published: July 2010

At the State Oil Company of Suriname, S.A., as oil reservoirs mature, increased water production is inevitable. Decline rates > 50% are common after water breakthrough. Significant reserves are bypassed when production watercuts exceeded 98% owing to limited artificial lift, transportation and /or processing capability.

Despite the limited successes in reducing the water production, in most cases, oil production is also reduced.

Similar to the concept of Cold Heavy Oil Production with Sand (CHOPS), where the strategy changed from Sand Control to Sand Production and Management, ESP technology is now used to maximize the fluid extraction rates in high watercut artificially lifted wells to achieve the required economical oil production rates. The realized Subsurface water disposal costs are much less than equivalent surface disposal costs.

In a 3-well ESP pilot[1], oil production rates increased from average 30 BOPD, 94% water on PCP to sustained 65 – 140 BOPD, 97% water on ESP (after 20 months). Additionally, in a remote field where all produced fluids were transported daily via barges to the nearest processing facility, subsurface produced water disposal reduced transportation costs by more than 25%, simultaneously creating additional storage capacity for increased oil production.

Neither ESP nor Subsurface Disposal technology is new. The paradigm change is that, at the planning stage, proactively designing completions, artificial lift equipment, processing facilities, and disposal well locations for the inevitable increase in water production, will minimize oil production decline as water production increases. The historically proven low economic success rate (<30%) of water control techniques together with the excellent success rate of high-rate high-watercut wells, clearly indicates that the oil industry needs to quickly shift (not abandon) from the water control to water management mode to economically recover the millions of bypassed reserves due to high water production after water breakthrough.
Developing Offshore Tight Gas Sands and Navigating Subsurface Uncertainty
Authors: Tucker Charles F , Dean Michael C. , Pahmiyer Robert , Bate Kevin , Omotosho Peter , Walli Fared , Ahmad Zulkifli , Brittingham Pete
Published: July 2010

Description of Material

The Danau-Bubut gas field was discovered in 1969 with the Danau-1 (DA-1) well. This discovery came between two major gas and oil field discoveries in Brunei; South West Ampa in 1963 and Champion in 1970. In light of economic conditions and technical challenges posed by Danau-Bubut at the time, field development was deferred. Over the subsequent three and a half decades the area was intermittently explored with limited success due primarily to poor quality log data upon which to base further action. In 2007 the company returned to re-explore the area with its sixth well. The well's success in 2007 led to two further appraisal wells in 2008–09. Equipped with new technology, extensive log, core, reservoir fluid, and well test information were acquired to more accurately describe the reservoirs and their contents. This paper will discuss several findings to date in context of subsurface uncertainty in tight gas sands and briefly overview future development plans.

Application

To successfully develop tight gas sands often requires more reservoir data than conventional reservoirs (Holditch 2006). The Danau-Bubut field is no exception. The reservoirs were deposited in a lower shore-face environment and thinly bedded, very fine grained sands are interpreted as storm events. Bioturbation is abundant in most shales and present in some sands. Rich in clays, the general reservoir quality degrades with depth due to compaction. Permeability ranges from 0.01mD to 1mD in reservoirs with 8% to 12% porosity with rare occurrences of thin interbedded high permeability sands. The structure is faulted into five main blocks and several smaller blocks. The use of seismic is largely limited to structure and major fault definition. The key to improved understanding of in place volumes was extensive logging, formation pressure tests and samples, coring, and subsequent well testing.

Results, Observations, and Conclusions

The last well drilled in the appraisal campaign finished operations in early 2009 and individually drill stem tested four different zones. The uppermost zone was stimulated with a hydraulic fracture. Results from each of the four zones and treatment were surprising. Three zones were capable of producing over 10 MMscf/day each and one zone was non-commercial. Detailed results from this appraisal well will be presented and discussed. Nonetheless, significant uncertainty remains and as a result, field development will be phased to accommodate future outcomes.

Significance of Subject Matter

The Danau-Bubut field is an example of opportunity that presents a different risk profile than normal and is unlike any other field currently operated in this company's portfolio. Understanding how to bring offshore tight gas volumes to market with Danau-Bubut will enable unlocking other similar offshore potential in Brunei.
Using MARS (Multiple Application Re-injection System) Technology for Improving Oil Recovery and Reducing Production Risk
Authors: Donald Ian , Sangster Ryan
Published: July 2010

Using MARS (Multiple Application Re-injection System) technology for improving oil recovery and reducing production risk.

Developing the optimum subsea production system is not a straightforward process. Balancing technical, reservoir and production requirements against an economic profile, can lead to compromises at the project development stage which often leads to sub optimal production later in field life.

Subsea production is expanding into deeper waters and more hostile environments. One technology that can help alleviate the dilemma between tackling the whole range of issues at project inception and the inevitable cost pressures is called MARS (Multiple Application Re-Injection System). MARS also facilitates IOR and EOR strategies in more mature basins, brownfield developments and greenfield projects.

By adopting a strategy for production that includes MARS technology, operators can build into a greenfield development plan, the capability to retrofit production enhancing technologies such as boosting or metering when they don't have the full range of knowledge which can only be gained when production is initiated. MARS also allows new or emerging technology to be introduced when the operator is comfortable with its performance hence reducing project and initial production risk. This approach facilitates maximum flexibility with minimum outlay.

In Dec 2009, Chevron used MARS technology to enable rigless subsea scale squeeze on the Lobito Tomboco field in Angola. The technology was first deployed commercially in 2007, when BP installed two multiphase pumps on the already producing King field in the Gulf of Mexico. Other projects since then include manifold and tree mounted multiphase metering, fluid sampling, production boosting and fluid intervention on both existing production systems and new projects.

MARS is being used in the North Sea, Gulf of Mexico and West Africa.

This paper will outline the proven benefits of adopting MARS technology to increase recoverable reserves and profitability while highlighting ongoing operational experience being gained in deepwater West Africa and the North Sea.
Deepwater Developments – Challenges from an Operator point of view: The essential combination of existing field experience with innovation and new technologies
Authors: Rambaldi Eric , Mackenzie Rory
Published: July 2010

Deep water fields represent a significant part of our future in term of oil and gas reserves. As a major Oil and Gas Operating Company, Total has been developing deep water fields for more than 10 years. If West Africa is the major contributor with numerous large and deep projects in Nigeria, Angola or Congo, new areas are emerging worldwide. If deep water developments are real opportunities for increasing level of reserves, they also mean real technological and economical challenges: –Going deeper means subsea boosting or flow assurance major issues.–Discovering smaller reservoirs brings economical challenges.–Facing more and more complex fluids imposes new subsea alternative architectures to deal with.–Tackling longer and longer tie backs raises subsea power transmission or flow assurance complex issues.

To face those challenges, the oil and gas industry needs to explore new technological avenues such as for instance all electric systems, subsea processing with gas/liquid or liquid/liquid separation, alternative materials or subsea autonomous intervention capacities with a low cost approach in mind.
A Predictive Tool for Rapid Estimation of Components Absorption in Lean Oil Absorbers
Authors: Bahadori A.
Published: July 2010

Absorption is one of the unit operations which is widely used in the oil and gas gas industries. The reproduction of the operating conditions of any plant, in particular, of a natural gas processing unit is, very important because modifications and procedures of optimization can be accomplished to increase the performance and the flexibility of the process and to maintain the economic competitiveness. In the present study, a robust and simple predictive tool is developed for rapid estimation of absorption efficiency as a function of absorption factor and number of absorber stages. Predicted results are compared with the reliable data and shows excellent agreement. The average absolute deviation between the experimental data and the proposed correlation was found to be around 1 %. Results indicate that the proposed method appears to be superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly if new data are available in the future. The predictive tool proposed in the present work is novel and unique expression which is non-existent in the literature. This is expected to benefit the oil and gas industries in making design amendments leading to informed decisions for the prediction of absorption/stripping efficiency for a given application in oil and gas processing industries.
Predictive Tool for Estimation of Potential Precipitation From an Equilibrated Calcium Carbonate Aqueous Phase
Authors: Bahadori A. , Vuthaluru H. , Ang M.
Published: July 2010

CO2 sequestration in saline aquifers has been proposed as one of the most practical options for reducing CO2 emissions into the atmosphere. Massive CO2 injection into an aquifer would alter the geochemical equilibrium between the rock-forming minerals and the formation water. In this work, a novel and simple predictive tool is presented to estimate the formation of calcium carbonate scaling as a function of pH, temperature, ionic strength of the solution, calcium cation concentration, bicarbonate anion concentration and carbon dioxide mole fraction when the water mixture is saturated with a gas containing CO2, to evaluate the effect of solution conditions on the tendency and extent of the precipitation. The proposed simple method covers concentration for calcium cation concentration, or bicarbonate anion concentrations up to 10000 mg/L, temperatures up to 90°C, total ionic strength up to 3.6 and pH values ranging between 5.5 and 8. The predicted values are found to be in good agreement with the reported data with average absolute deviations being less than 2.6%. The proposed tool is superior owing to its accuracy and clear numerical background based on Vandermonde matrix, wherein the relevant coefficients can be retuned quickly for various cases.
Calculating Equivalent Fracture Network Permeability of Multi-Layer-Complex Naturally Fractured Reservoirs
Authors: Jafari A. , Babadagli T.
Published: July 2010

Modeling naturally fractured reservoirs (NFRs) requires an accurate representation of fracture network permeability. Conventionally, logs, cores, seismic, and pressure transient tests are used as data base for this. Our previous attempts showed that a strong correlation exits between the fractal parameters of 2-D fracture networks and their permeability (Jafari and Babadagli, 2008, 2009a). We also showed that 1-D well (cores-logs) and 3-D reservoir data (well test) may not be sufficient in fracture network permeability (FNP) mapping and 2-D (outcrop) characteristics are needed (Jafari and Babadagli, 2009b). This paper is an extension of these studies where only 2-D (single layer, uniform fracture characteristics in z-direction) representations were used.

In this paper, we considered a more complex and realistic 3-D network system. 2-D random fractures with known fractal and statistical characteristics were distributed in the x-, and y-directions. Variation of fracture network characteristics in the z-direction was presented by a multi layer system representing three different facieses with different fracture properties. Wells were placed in different locations of the model to collect 1-D fracture density and pressure transient data. In addition, five different fractal and statistical properties of the network of each layer were measured.

The equivalent fracture network permeability (FNP) was calculated using a commercial software package as the base case. Using available 1-D, 2-D, and 3-D data, multivariable regression analyses were performed to obtain equivalent FNP correlations for many different fracture network realizations. The derived equations were validated against a new set of synthetic fracture networks and conditions at which 1-D, 2-D and 3-D are sufficient to map fracture network permeability were determined. The importance of the inclusion of each data type i.e. 1-D, 2-D and 3-D, in the correlations was discussed.
Efficiency Analysis of Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method for Heavy-Oil Recovery
Authors: Al Bahlani Al Muatasim , Babadagli Tayfun
Published: July 2010

Heavy-oil recovery from fractured carbonates is a real challenge, yet no proven technology exists as an efficient solution. Reservoir heating is generally inevitable and steam injection is the only effective way to heat heavy-matrix oil in such reservoirs using the steam distributed through fracture network. We propose a new method minimizing heat needed for efficient heavy-oil recovery from oil-wet fractured rocks by adding solvent component. Efficiency is a critical issue in this process due to potentially high cost of the process.

A new technique we proposed previously called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) consists of a cyclic injection of steam and solvent in the following manner: Phase-1: Steam injection to heat up the matrix and recover oil mainly by thermal expansion, Phase-2: Solvent injection to produce matrix oil through diffusion-imbibition-drainage processes, and Phase-3: Steam injection to retrieve the injected solvent and recover more heavy-oil. Laboratory scale static and dynamic experiments had shown that, under very unfavorable conditions (oil-wet matrix, 4,000cp crude), oil recovery at the end of Phase-3 was around 85-90% OOIP with 80-85% solvent retrieval.

In this paper, the experimental results obtained earlier were matched to a single matrix/single fracture numerical model and parameters needed for field scale simulation (matrix-fracture thermal diffusion, solvent diffusion and dispersion coefficients) were obtained. Using the data obtained through matching, field scale simulations were performed for efficiency analysis and to identify the optimal injection schemes (soaking time for cyclic and injection rate for continuous injection) and durations, and surface steam quality. Specific conclusions as to how to apply this technique efficiently in the field considering the cost of the process were reported.
Robust Well Test Interpretation by Using Nonlinear Regression with Parameter and Data Transformations
Authors: Dastan Aysegul , Horne Roland N.
Published: July 2010

Nonlinear regression is a well-established technique in well test interpretation. However, this widely-used technique is vulnerable to issues commonly observed in real data sets, namely sensitivity to noise, parameter uncertainty, and dependence on starting guess. In this paper, we show significant improvements in nonlinear regression by using transformations on the parameter space and the data space. In addition to providing more accurate results, faster convergence, and reduced sensitivity to starting guesses, our techniques can also provide noise reduction and data compression.

The first part of the paper discusses the basis of parameter transformations and gives suitable transform pairs for common reservoir parameters. We analyzed the homogeneous probability distribution of transformed parameters using Monte Carlo analysis and verified that the transform pairs proposed generate Cartesian parameters. We found performance improvement in terms of faster convergence and increased probability of convergence for a random starting guess.

The second part of the paper discusses nonlinear regression using the wavelet transformation of the data set. The wavelet transformation is a process that can compress and denoise data automatically. By using regression on a reduced wavelet basis rather than the original pressure data points we achieved improved performance in terms of likelihood of convergence and narrower confidence intervals. We investigated four different wavelet strategies, which differ in the method of choosing a reduced wavelet basis.

Combinations of the techniques discussed in this paper were used to analyze 20 data sets to find the technique or combination of techniques that work best with a particular data set. Using the appropriate combination of our techniques will allow for more reliable estimation of reservoir parameters using nonlinear regression.
Slim-Well Completions: A 3D Numerical Approach for Displacement to Design Effective Cementing Fluids
Authors: Pks S. , Yerubandi K. B.
Published: July 2010

Slim-well construction helps to significantly reduce overall well construction costs. The first step of the successful completion process is achieving effective zonal isolation. Slimhole configurations experience higher shear rates at standard annular pump rates as compared to conventional configurations. The increase in shear rate could exacerbate intermixing of the fluids, diffusion, and fingering in the annulus, thereby leading to incomplete mud and filter-cake removal and poor cement placement. Real-world consequences of these phenomena can include interzonal communication, loss of production, remedial squeeze work, and even well abandonment. Whether a conventional or slim hole well, designing an effective zonal isolation job involves balancing two technical challenges: (1) providing adequate hole cleaning through effective erodibility shear stresses; and (2) reducing channeling of mud or spacer by minimizing intermixing at fluid interfaces, controlling diffusion and minimizing fingering in the annulus. This paper deals with the underlying interactions between fluids and the challenge of controlling the aspects affecting intermixing

Intermixing lengths can commonly be as high as 500 feet for slimhole cementing jobs owing to the large difference between central and peripheral velocities of the annular fluids. In an attempt to minimize this problem, a three-dimensional (3D) numerical fluid-flow simulator was used to compare flow profiles in a low clearance 143/4-in. × 133/8-in. annulus to those in a conventional 16-in. × 133/8-in. annulus. Rheologies of the annular fluids were accurately modeled using the Herschel-Bulkley scheme. Using the same fluids and pump rates, numerical simulations in the slimhole configuration clearly showed worse displacement as compared to the standard configuration. The effects of the three rheological parameters viz., τ0, µ∞, and n of the fluids, pump rate and eccentricity on dynamic velocity profiles, displacement efficiency, intermixing lengths, and top of fluids were then studied to improve drilling-mud removal, and cement slurry placement. Results of various simulations are shared to reveal the properties and parameters that are needed to help achieve a competent cement sheath over the desired interval.