bluuebunny/crossref_metadata_2025 huggingface dataset:
A Rapid and Efficient Production Analysis Method for Unconventional & Conventional Gas Reservoirs
Authors: Jordan C. L. , Smith C. R. , Jackson R.
Published: December 2009

Currently, there is an industry assortment of production analysis methods ranging from traditional decline and type curve matching to rate-pressure normalization techniques and detailed production history matching. Yet despite its many limitations, conventional decline analysis is still commonly used in gas (and oil) production analysis due to its minimal data requirements and ease of application (regardless that without modification the method cannot be used to estimate reservoir properties or formation damage). As a result, this paper presents an automated computer method for estimating original gas-in-place and other reservoir flow parameter for conventional and unconventional gas reservoirs. This procedure overcomes the limitations of convention decline in which the analyst must properly select the type of decline to avoid erroneous forecasts, as well as more exotic methods requiring iterative computational procedures.

Onshore and offshore case studies and examples presented in this paper will demonstrate that a modified decline and production analysis procedure will allow for proper identification of flow regimes, reliable evaluation of drainage area and OGIP, and the prediction of future deliverability and depletion. Case studies will also show that up-scaled and aggregate reservoir properties can provide a real measure of gas well deliverability and therefore a simpler, time-efficient model analysis can be used. Data uncertainty, PVT error, stimulation appraisal, gas storage system (free or complex mechanisms such as absorbed gas) and other factors will be discussed in the context of the case studies, and general reservoir management.

When used appropriately, the approach is generally accurate and robust enough that it can provide valuable information in circumstances of poor data quality. Finally, the procedure is extremely simple and can be implemented in desktop applications or spreadsheets with minimal computational effort.
Cementing Challenging Shallow Gas Wells in Central Asia
Authors: Arangath R. , Zhukin A. , Primbetov T. , Jandauov A.
Published: December 2009

A large shallow gas development project in a remote area of Kazakhstan was recently started. The project will include different phases for commercial gas production from a shallow gas bearing sandstone reservoir. The first phase will require at least 320 wells to be drilled and completed. Due to the presence of shallower over-pressurized gas zones above the production zone, the pore and fracture pressures margins during cementing are very narrow. These narrow margins represent a challenge when cementing these wells: being able to place the cement in the annulus without losses while providing sufficient hydrostatic pressure to control the shallow gas zone pore pressure.

The first 4 wells showed poor cement bonds and sustained casing pressures. Due to these sustained pressures the environmental authorities did not allow these wells to be produced and therefore the operator was faced with the requirement to change the design criteria and the fluids design used during the cementing operations of these wells.

The cementing fluid composition was changed along with the cementing placement and post placement techniques in order to obtain wells without sustained casing pressures. The criteria to evaluate a successful cement job for this project were set as follow: No losses while placing the cement across the pay zone.Good zonal isolation based on acoustic cement bond logs.No sustained annulus pressure during well test and well production.Repeatability of results obtained from one well to the other.

First, a gas migration prediction software is utilized to predict gas migration and its severity. Then, depending on the severity and other well conditions, the type of gas migration additive and the additive concentration is selected and tested in the laboratory. Proper cement placement is then verified by a modeling tools predicting placement pressures, u-tube and mud removal. Finally the post placement technique during the critical cement hydration period where gas migration can occur is selected using other modeling tools

The results obtained have been observed on more than 16 wells thus confirming the accuracy and the repeatability of the engineered approach adopted. It is believed that such results could be implemented in other shallow gas fields in Kazakhstan and in other parts of the world that are drilled through similar geological formations and with narrow pore and fracture pressure margins.
Obesity and Employment
Authors: Kuo Wei-Hua
Published: December 2009

Obesity is costly to employers in terms of higher medical costs, loss of productivity, increased medical sick leaves, and premature medical retirements. Specifically, research shows that:

Overweight and obese employees have higher rates of sick leaves and disability. Workplace injuries are more frequent among overweight and obese employees. Healthcare costs, based on claims data analyses, are also consistently higher for employees with higher body mass indices. Thus, obesity is an important driver of costs in the workplace. BMI (Body Mass Index: Weight in kilograms / Square of height in meters) is an independent predictor for short-term disability events: being overweight and obese raise the odds by 26% and 76%, respectively. "Optimal BMI" for employees occurs at about 25 to 27 kg/m2, above which the indirect and direct costs to employers increase with increasing BMI. "Obese workers have the highest prevalence of work limitations (6.9% vs. 3.0% among normal-weight workers), hypertension (35.3% vs. 8.8%), dyslipidemia (36.4% vs. 22.1%), type 2 diabetes (11.9% vs. 3.2%), and metabolic syndrome (53.6% vs. 5.7%)." Furthermore, increased prevalence rates were also found among those classified as overweight
Optimizing the Development Concept of a Mature Gas Field in Intensive Drilling Context: Tunu Field Case
Authors: Widyoko Bhayu , Plathey Daniel , Boireau Clement , Payer Nicolas
Published: December 2009

First developed in 1990, intensive studies that were conducted after 10 years of production of the Tunu field showed that due to its heterogeneity, the lateral connectivity of the Tunu reservoirs was not sufficiently addressed by the initial drilling pattern. The next phases of Tunu development plan would then involve the drilling of infill wells with reduced spacing. By 2005 the operator estimated that 800 new wells would need to be drilled, at a rate of 60 wells per year, in order to maintain the field potential and achieve the targeted recovery factor. In addition, with low incremental reserves per well, the main challenge that the operator faced, was to reduce the cost of drilling infill wells, to preserve the economics of the development projects. The stakes for cost reduction were very high, as the Tunu field represented half of Mahakam PSC's remaining gas reserves and was expected to remain its biggest producer for years to come.

This paper illustrates the different design and operational optimization efforts that have been undertaken since 2005 in the framework of cost reduction exercises involving different disciplines: drilling, completion, surface facilities, and development project. Analysis performed in 2008 showed that, at constant market conditions, the successful optimization process on 2 projects sanctioned in 2006/2007 contributed to around 300 MUSD of savings, whilst long term potential cost savings are estimated to be more than 2 BUSD of the 8 BUSD initial capex estimate.
Improving an Established Measurement while Drilling System through a Partnership for Integrating a Unique Logging while Drilling Resistivity Tool for Applications in China
Authors: Lee Jonathan , Macune Don , Lin Qui , Chumming Wei , Zhishen Yun , Hongwei Li
Published: December 2009

Logging While Drilling (LWD) resistivity tools have been developed and built by the major service companies to address while-drilling formation evaluation needs since the mid-1980s. Whilst such devices are considered standard components in many markets, the smaller, independent service companies are typically unable to both develop and manufacture tools with the accuracy and performance of those offered by the majors cost-effectively. In order for them to enter the LWD market they have historically purchased complete Measurement While Drilling (MWD) and LWD systems from a single manufacturer or individual components from multiple suppliers. The authors describe how through partnership a unique gamma and resistivity tool was adapted to interface directly into an existing MWD platform, enabling the service company to offer logging services in directional and horizontal wells in an established field in China and to compete in a wider area of operations.

To ensure the successful application of the LWD tool with the MWD platform, the development and testing of the physical interface was backed up with comprehensive training on field operations and use of the logging software provided to the service company. After testing the interface successfully on a non-commercial well the system was deployed on a subsequent horizontal well to allow real-time adjustment of the well path through analysis of the resistivity measurements.

The paper offers case studies of the system in use in China and outlines the benefits seen through the relationship established between the tool manufacturer and the service provider, who have their own established MWD platform.

The success of this partnership demonstrates that close commercial and technical cooperation between LWD manufacturers and service companies can result in significant expansion of service offerings—considerably expanding the options open to operating companies—without incurring significant and repeated investments in new technology.
Innovative and Proactive Major Hazard Management in South East Asia
Authors: Noersoesanto Eko
Published: December 2009

EXTENDED ABSTRACT

Description

Major Hazard Management (MHM) of high risk production installation is achieved by oil and gas operators by complying with applicable regulations and adopting various practical and innovative risk management techniques. The learning from offshore and onshore disasters is bringing new levels of best safety practice into the industry. Premier oil has developed a MHM programme for its global asset, which is successfully implemented in South East Asia.

Premier Oil approach for existing facilities (Anoa Field platform complex and FPSO) comprises the following elements: Conducting a regular ‘thorough review’ of existing Safety Cases;Including ‘best practice’ into the review, i.e. Bow-Tie and Swiss-Cheese analysis, new guidance on developing process safety indicators (HSG254) and the learning from UK Health and Safety Executive Maintenance Management Review (KP3);Establishing a verification scheme to confirm full functionality of SCEs and pioneering a ‘Case to Operate’ for any degraded SCEs;Performing six monthly revalidation of SCEs performance against the assumptions used in the Safety Case;

Premier Oil intends to extend this approach to its new development in South East Asia i.e. Gajah Baru in Indonesia and Chim Sao in Vietnam.

Applications

Local regulations in South East Asia do not always require a Safety Case or Verification Scheme for high risk offshore production facilities. Premier Oil is implementing this MHM programme to comply with its corporate policy of reducing risk to ‘as low as reasonably practicable’ of where it operates. As such this process will demonstrate the best combination of theoretical, practical, proactive and reactive steps to control Process Safety and other Major Accident Events on any new build, existing or aging offshore production installation.

Conclusion

The MHM process described will deliver an assurance process for any high risk installation over its working life and can be implemented at any stage of the lifecycle
Responding to an Inland Oil Spill in Remote Areas
Authors: Tan Wilson
Published: December 2009

Oil spill response is generally considered to be a maritime issue. Despite not necessarily receiving the most coverage, inland spills do happen and may actually occur more frequently than we perceive. In fact, one of the largest spills found in literature is the 1992 Fergana Valley spill in Uzbekistan (more than 80 million gallons). As such, the challenges faced in responding to an inland spill merit wider discussion.

Many inland oil fields are located in regions of extreme climate where conditions can be brutal. Responders, who are not acclimatised, will find working in these conditions tough when they are on-site. This, coupled with the harsh terrain, will increase the risks exposed to responders. As such, it is important to put in place guidelines and measures to ensure the health and safety of personnel.

In some situations, difficulty in communications between different teams may arise due to the large area of operations. This can be further exacerbated by the surroundings; for instance, teams may be located in different low-lying regions separated by highlands rendering communications via mobile phone – and sometimes, even satellite phones-ineffective. Measures must therefore be put in place to ensure that the security of all personnel is not compromised.

Inland oil fields are often in remote locations which makes response an extremely complicated logistical exercise. Conventional oil spill response equipment such as booms and skimmers may be inappropriate and strategies employing manual clean up will likely be required. Additionally, the inaccessibility presents another set of problems pertaining to waste management.

This paper discusses the key issues faced during an inland oil spill response. The paper will use a case example from the recent Yemen oil spill to discuss the pertinent operational issues.
Integration of Fluid Log Predictions and Downhole Fluid Analysis
Authors: Zuo Julian Y. , Mullins Oliver C. , Dong Chengli , Zhang Dan , O'Keefe Michael , Dubost Francois X. , Betancourt Soraya S. , Gao Jinglin
Published: December 2009

Reservoir fluids frequently reveal complexities in hydrocarbon columns. Fluid compositional grading is usually caused by gravitational forces, thermal gradients, biodegradation, active and multiple charging, water washing, leaky seals, and so on. Moreover, formation compartmentalization leads to discontinuous fluid distributions. Hence, the assessment of compositional grading and the recognition of flow barriers or compartmentalization in hydrocarbon reservoirs is vital to accurate formation evaluation, effective and efficient production and management. The downhole fluid analysis (DFA) logs provide a useful tool to determine the compositional gradients and delineate possible compartmentalization in real time at reservoir conditions.

In this paper, a methodology/workflow was developed to integrate DFA log predictions with real time DFA logs using an equation-of-state (EoS) approach. The DFA logs provide downhole fluid compositions of CO2, C1, C2, C3-5 and C6+, coloration (optical density, OD) associated with asphaltene contents, live fluid density and viscosity, oil based drilling mud (OBM) contamination, formation and DFA flowline conditions, etc. These real time measured data are treated as the inputs to the fluid EoS model. The fluid delumping and characterization procedures are applied to obtain the detailed compositions and to establish the EoS model (Zuo et al., 2008). The EoS model is built up by matching a part of DFA log data. Fluid profiles are then predicted by the EoS model. The DFA log predictions are compared with the real time DFA logs to reveal the complexities in the hydrocarbon columns. Case studies are presented to show how the methodology is successfully used to investigate reservoir complexities. The results indicate that the new workflow provide a useful tool in reducing the uncertainties related to compositional grading and reservoir compartmentalization as well as in optimizing the DFA logging during acquisition while the tool is still in the well.
Development of Microbial Conversion Process of Residual Oil to Methane in Depleted Oil Fields
Authors: Maeda H. , Miyagawa Y. , Ikarashi M. , Kobayashi H. , Sato K. , Sakata S. , Mochimaru H.
Published: December 2009

Methane is a clean-burning fuel that is the main component of natural gas. We have attempted to develop a methane-producing system using indigenous microbes in depleted oil fields. In particular, we aim to combine a microbial conversion of the residual oil into methane with the geological sequestration of carbon dioxide: First, hydrogen-producing bacteria are harnessed to produce hydrogen from residual petroleum components in the depleted oil reservoir. Next, methane-producing microbes (methanogens) utilize the hydrogen and carbon dioxide, which is injected for geological sequestration, to generate methane. Resulting methane is therefore a carbon-neutral fuel.

As the first step, we successfully isolated multiple hydrogen- and methane-producing microbes (10 hydrogen-producing bacteria and 4 methanogens) from depleted oil fields in Japan. Strikingly, our analysis of inoculums incubated under high temperature and high pressure, the condition similar to native conditions inside of petroleum reservoirs, revealed that indigenous microbes in the reservoir brine are capable of generating methane by utilizing crude oil and carbon dioxide. Consumption/production rate of gases (methane, carbon dioxide) and acetic acid indicated that the methane production under reservoir conditions is likely mediated through two pathways; the aceticlastic (acetic-acid utilizing) and the hydrogenotrophic (hydrogen and carbondioxide utilizing) pathways. Furthermore, by analyzing methane-producing ability of isolated microbes, we found that the syntrophic cooperation between hydrogen-producing bacteria and methanogens is critical for the methane production under the resavoir condition.

We are currently determining optimal combination(s) of these microbes to achieve an efficient methane production in the depleted oil field. Our next step will be to establish a method to enhance methanogenic activity of the microbes as well as an effective methanogenesis in porous media, the condition inside of actual reservoirs (porous rock formations). Ultimately, our endeavor will enable a sustainable carbon-cycling system that converts residual oil and stored carbon dioxide in depleted oil fields into environmentally friendly bio-methane.
Feasibility Study of Drill Cuttings Re-Injection in the Ahwaz Field Iran
Authors: Majidaie Saeed , Shadizadeh Seyyed R.
Published: December 2009

Upstream environmental policies require the use of best available and economically sound technology to continually reduce discharge of mud and cuttings waste resulting from drilling operations. Downhole disposal of mud and cuttings waste through hydraulic fracturing, Drill Cuttings Re-injection(DCRI), is often the preferred waste management option because it can achieve true zero discharge without being limited by the drilling location and it is also economically favorable.

Iran's petroleum industry produces large amount of drilling wastes annually. The giant oilfields, the wide drilling operations without any plan to treat or to dispose of wastes, cause so dangerous environmental problems that damage the agriculture and animal husbandry in these fields.

This paper tries to investigate the possibility of drill cuttings re-injection (DCRI) in Ahwaz oilfield. The volume of drilling waste is calculated for a typical well. Disposal formation selection is the next important and sensitive step. By using a hydraulic fracturing simulator, the lateral and vertical extent of the fractures can be estimated and modeled to ensure they do not cut across overlying sealing beds, intersect with other well bores, natural fractures, faults, drinking water aquifers.

A data gathering for subsurface geology and logging analysis and also the position of potable water sources and recoverable hydrocarbons throughout the field are shown that the Mishan formation is more appropriate for DCRI. The depth of almost 5000 ft of Mishan assures that created fractures are developed below enough underneath surface and far from hydrocarbon reservoir in 10000 ft depth. Numerous scenarios were considered in the feasibility studies to ensure that fractures do not breakthrough to surface during cuttings re-injection in the absence of stress or permeability barriers of upper formations. Even under the most severe conditions, it was found that the generated cuttings slurry could be safely injected.
How to Reduce the Risk of Over-Drilling in Fractured Carbonate Reservoir: A Case Study in East Indonesia
Authors: Yang Siyu
Published: December 2009

A majority of wells in the fractured carbonate reservoir are currently experiencing high water cut. Developing such a fractured carbonate reservoir presents extreme reservoir engineering and geological challenges. Considering how many infilling wells are required to obtain optimal recovery before drilling, this paper offers some insights on how to reduce the risk of overdrilling in fractured carbonate reservoir based on some successful experiences in East Indonesia. Wigner-Ville Distribution technology (WVD) was used firstly in Indonesia to predicate hydrocarbon distributions by using 2D/3D seismic data only. The results could indicate the favorable reservoir.Discrete Fracture Network (DFN) in software FracMan was employed to construct reliable 3D fracture model which demonstrates the fracture spacing, orientation, aperture, geometry and its relationships.

Above integrated studies were used as a guide to determine one infilling well target and the drilling results proved this methodology is successful in reducing the risk of over-drilling and well interference in such complex fractured reservoir.
Successful Application of New LWD Platform Provides Integrated Real-Time Formation Evaluation in the Mediterranean Reservoirs
Authors: Neto Aristides Orlandi , Dutta Dhruba , Hassan Saad
Published: December 2009

As the global power scenario changes with increased demand for oil and gas, remote and challenging (deepwater offshore, high pressure-high temperature, high-angle wells) locations are drilled in an ever-demanding exploration effort with minimum or no experience in the area. To meet the demand and associated financial implications, operators are drilling highangle wells that require special care from well stability, completion, and formation evaluation, to name a few. Complex reservoirs require complex trajectory and therefore proper well placement. To place a well accurately, the evaluation of acquired data requires real-time interpretation. In Egypt, Petrobel is following the trend and has been drilling deviated wells to enhance production in the Mediterranean by using a new logging while drilling (LWD) platform for formation evaluation. The data delivered by this service includes not only traditional measurements such as resistivity, density, neutron porosity, gamma ray, and caliper, but also induced spectroscopy and sigma. The sigma measurement is used for saturation evaluation independent of resistivity. The availability of two independent saturation estimations provides additional confidence. Spectroscopy provides formation mineralogy and accurate clay fraction, which enhances shaly sand interpretation. Formation evaluation in real time provides accurate estimates of hydrocarbon in place and allows for comprehensive decision making. The field is approximately 70 km from the coast of Alexandria, Egypt. The main reservoir is predominantly sandstone with gas and condensate. Highlighted in this study: Real time interpretation based on capture spectroscopy and sigma combined with the traditional measurements.Lithologic and mineralogic evaluation using capture gamma-ray spectroscopy measurements on LWD in real time.Independent gas saturation estimates from both resistivity and sigma measurements on LWD in real time.Real time formation evaluation requires minimum inputs from user, making it a powerful tool for operators in the decision making process.
Challenges in Managing Mercury in Malaysia
Authors: Zainal Farid M. , Yusoff M. R.
Published: December 2009

Mercury is a heavy metal naturally present in the produced crude oil and condensate. PETRONAS Carigali Sdn Bhd (PETRONAS Carigali) operates in basins where levels exceed the norm resulting in accumulation of the heavy metal within the process line and an increased risk of exposure to workers during its operations.

Within Malaysia, the permissible exposure limit (PEL) and biological exposure indices (BEI) of Mercury are as per the American Congress of Governmental Industrial Hygienists (ACGIH) yearly published limits. However, these levels are of limited use for the oil and gas industry as well as for workers in Malaysia for the following reasons Permissible exposure levels are based on continuous exposure of 8 hours a day for 5 days a week. This is applicable to mercury exposure in battery making factories and such. However, the usual exposure for offshore workers are two weeks offshore (exposure time) followed by two weeks onshore (non-exposure).The BEI is based on the general American population. In some regions of Malaysia, locals consume seafood exceeding twice a day causing an ambient level of mercury on blood to be way above the BEI.

With this, the challenges faced by PETRONAS in dealing with Mercury exposure include government guidelines using ACGIH limits, lack of published data on mercury exposure studies in the oil and gas industry, no information on baseline levels of mercury in blood for local residents in different parts of Malaysia and limited local laboratory capabilities in analyzing for different species of mercury. On top of this, the most challenging issue is communicating mercury hazard information and explaining exposure data to workers.

In summary, this paper highlights the issues and challenges faced by PETRONAS Carigali in managing Mercury as a health hazard in the workplace and efforts to overcome them.
A New Efficiency Criterion for Acid Fracturing in Carbonate Reservoirs
Authors: Newman M. S. , Rahman M. M.
Published: December 2009

The success of a stimulation technique is often measured by its stimulation ratio. This paper, however, presents a novel way of calculating the value that can be added from acid fracturing. A model predicting the effect of acid fracturing in carbonate reservoirs has been developed. The model accounts for fracture geometry and for acid fracturing job specifications.

Acid fracturing is typically conducted in carbonate reservoirs, which make up approximately 70% of the worldwide hydrocarbon reserves. Acid Fracturing is a complex process depending on multiple factors which are different in nature, making mathematical models unreliable. Due to the stochastic process inherent in acid fracturing, modeling has been met with difficulty, especially in calculating conductivity. The modeling data analysis includes the sensitivity study with respect to fracture length and fracture width, as well as the importance of efficient acid transport.

The post-stimulation production data is used to calculate the cumulative production parameter which is the cumulative production over a given period of time. It can also be compared to the production of an un-stimulated case. The cumulative production parameter offers a unique way to calculate acid fracture value. This parameter gives a tangible value which translates to production over time. More importantly, the proposed model allows fractures from different reservoirs to be accurately compared, helping production engineers make better decisions and estimate the acid treatment efficiency.
Reservoir Management and Optimization of Matured Field Using WAG Injection: Implication Of A New Upgridding Technique in Baram Field
Authors: Ataei Abdolrahim , Darman Nasir , Liang Ooi Kok , Masoudi Rahim
Published: December 2009

Baram field is one of the nine major oil fields in Baram Delta Operation (BDO) area which is located 28 km northwest of Lutong, in the offshore area of Miri, Sarawak in East Malaysia. The field has been producing since 1967 with multiple stacked sandstone reservoirs in a shallow offshore environment. Based on the BDO EOR feasibility study conducted in 2004 the field has been selected as one of the major EOR candidates in the area.

This paper describes a successful application of the PETRONAS upgridding technique in Baram field. The so called "Optimum Grid Coarsening Scheme" uses fine grid static and dynamic reservoir variability to identify the non-uniform grid cell configuration at the coarse grid model. Averaged saturation equation is the key driver in calculating the sub-grid properties in the fine level that subsequently will be the basis for determining the coarse grid scheme. It considers the balance of all forces including gravity, viscous and capillary that contribute to fluid flow in the reservoir.

The upscaled model has been successfully history matched with the past 40 years of production and pressure history in a timely manner with limited adjustment of the static parameters. The history matched model was then used in our study to investigate many possible development scenarios in order to improve the ultimate recovery factor of the field. In our study, Water Alternative Gas (WAG) injection has shown superiority over other studied methods as the most promising EOR scenario for the field. The study shows that the recovery factor of the S sand in Baram can be increased by an additional of 16% above infill drilling and 7% above water flooding options using WAG application.
A Simple Method for Prediction of Transport Properties of Carbon Dioxide
Authors: Bahadori A. , Vuthaluru H. B.
Published: December 2009

In the present work, simple-to-use correlation, which is simpler than current available models involving a large number of parameters, requiring more complicated and longer computations, has been developed for the prediction of transport properties (namely viscosity and thermal conductivity) of carbon dioxide (CO2) as a function of pressure and temperature. The adjusted coefficients of correlation have been optimized through an efficient and reliable algorithm by minimizing the standard deviation of predicted values in comparison with the reported reference data by solving the system of equations. The proposed method to develop correlation appears to be superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned if more data are available in the future. The correlation developed accurately works for temperatures between 260 K and 450 K as well as pressures between 8 and 70 MPa which is the range of pressure that is widely considered in carbon dioxide (CO2) sequestration. Results have been compared with the reported reference data and excellent agreement has been obtained between the predicted results and observed values. The average absolute deviations were found to be 2 and 2.5 percent for viscosity and thermal conductivity of carbon dioxide respectively.
Rendering Mature Assets more HS&E Compliant through Improved Corrosion Management
Authors: Morshed Ali
Published: December 2009

As offshore assets age they become more susceptible to hydrocarbon leaks and failures due to corrosion issues. Thus, they pose a greater threat progressively to the personnel's health and safety and also to the protection of the surrounding environment. An efficient way to reverse this trend is to create and implement an asset corrosion management strategy (asset CMS) which would simultaneously improve asset integrity and enhance plant uptime through reducing the number and severity of hydrocarbon leaks (due to corrosion), hence improving both personnel safety and environmental protection.

Such an asset CMS would improve HS&E compliance (in particular in regard to the HSE's KP3 Report and its findings) onboard an offshore asset through pre-empting sections of the process systems before they can develop into a failure due to corrosion.

This paper contains real data collected over a five-year period illustrating how the above has been achieved for an offshore asset in the North Sea through reducing the number and severity of hydrocarbon leaks over time, thus improving personnel safety and environment protection in particular and making the asset more HS&E compliant in general.
Laser, Mono-Diameter Drillstring with Resin Spray Casing Completions
Authors: Kurawle Irfan , Kaul Mohit , Mahalle Nakul , Carvalho Vickey , Kulkarni Nikhil , Shivanikar Anand
Published: December 2009

The industry has come a long way since the inception of drilling from cable too rig to rotary drilling. The method of drilling has not changed at all in the last couple of decades. The advancement of technologies have lead to development of high power lasers which can be used to blast through the rock at rates greater than 200 ft/hr. We would like to introduce the a new laser drilling system which can drill a mono diameter hole and simultaneously build a casing around the wellbore using high pressure spray devices to spray a heat setting resin which is then pressed using a heated drum roll to give a perfect smooth casing wall. A second jet with low temperature air is used to cure the resin thus setting it faster than the conventional way. The resin is capable to sustain pressure up to 4885 psi and thus making it a likely candidate for HPHT wells. It is highly resistant to chemical corrosion and is non-rusting thus enhancing the life of the completion. The complete drill string design would be discussed in detail providing the next 21st century tool for the drilling industry to drill through any possible formation encountered.
Studying the Effects of Pore Geometry, Wettability and Co-Solvent Types on the Efficiency of Solvent Flooding to Heavy Oil in Five-Spot Models
Authors: Dehghan A. A. , Kharrat R. , Ghazanfari M. H. , Farzaneh S. A.
Published: December 2009

Pore geometry and wettability are fundamentally the most important parameters that control the miscible displacement efficiency of oil reservoirs. Understanding the physics of solvent flooding process in micro scale can result in significant improvement to better describing the miscible processes observed in laboratory and in the field. However, displacement behavior of a co-solvent at different wettability conditions under the influence of pore geometry in five-spot models remains a topic of debate in the literature. Here, miscible solvent injection experiments performed on several one-quarter five spot glass micromodels. Network patterns with different pore geometries along with those obtained from thin sections of sandstone and carbonate rocks were used in the experiments. Wettability of the micromodels was altered towards strongly water-wet and oil-wet conditions by applying a new chemical procedure. Influence of four different groups of chemicals and their mixtures as co-solvents as well as the effect of pore geometry parameters, on microscopic and macroscopic displacement efficiency in both strongly wetted media have been investigated. Precise analyses of the high quality pictures provided continuously during experiments were used to explore the solvents' displacement behavior. An optimum mixture of co-solvents with greatest sweep efficiency was determined. The results showed that the displacement efficiency of the solvents is generally higher in strongly water-wet medium, but its extent is dependent on pore geometrical factors. Star-shape pores with higher coordination number and lower pore-throat size ratio showed maximum displacement efficiency. In addition, the sweep efficiency in heterogeneous patterns was in the range of the data obtained from network patters with similar geometrical parameters. The microscopic observations confirmed that the presence of connate water in strongly water-wet medium could improve the final recovery, while the recovery factor in absence of connate water was not affected majorly by surface wettability.
Advances in Granitic Basement Reservoir Evaluation
Authors: Le Van Hung , Farag S. , Mas C. , Maizeret P. D. , Li B. , Dang T.
Published: December 2009

Granitic basement reservoirs have been the focus of increasing attention in the Asia Pacific region in recent years, following several new oil and gas discoveries in this complex reservoir type.

Accurate formation evaluation in fractured, crystalline, granitic reservoirs is notoriously difficult. Furthermore relatively little research has gone into understanding logging tool response or pressure transient behavior in these reservoir types, and developing suitable workflows for formation evaluation.

In this paper the authors propose an improved methodology for integrating various open-hole logs, production logs and well test data to better evaluate the reservoir potential of a fractured granitic formation. Since the wells are either horizontal or highly deviated, the framework also serves as one of the primary methods to asses the lateral extent of the reservoir.

A case study from the region is used to illustrate the workflow. Image log interpretation, advanced acoustic measurements, nuclear logs and production logs with distributed local sensors are combined with well test data to derive the best possible evaluation of the fracture network around the borehole and the degree of connectivity with the reservoir at large. The advantages and limitations of the proposed workflow are also discussed and the stage set for further work in this complex environment.
Deepwater Casing String Deployment for Elimination of Rat Hole Section: Retractable Shoe Joint
Authors: Groesbeck Brad Michael , Jordan John Christopher
Published: December 2009

This paper describes the development of a deepwater casing shoe which ensures subsea casing strings designed to land in a wellhead can be run to full wellbore depth with no rat hole. The problem with excess rat hole occurs when drilling and hole-cleaning operations enlarge a normally-gauged hole or the unsupported, uncemented portion of the wellbore collapses and leaves an over-gauged hole. Such hole conditions are conducive to compromised primary cementing operations, poor zonal isolation, and can lead to stuck logging or other downhole tools in the subsequent interval.

This shoe allows the rat hole section to be completely covered with casing while simultaneously landing the subsea casing hanger in the wellhead. This technology represents a paradigm shift in primary cementing practice; allowing cement to be placed at wellbore TD without a rat hole. This is especially true in deviated and/or horizontal wellbores, where zonal isolation is critical to well-life expectancy and production.
Effective Perforating and Gravel Placement: Key to Low Skin, Sand-Free Production in Gravel Packs
Authors: Saebi Shahryar , Jain Samyak , Tibbles Raymond , Munro Jock , Suppiah Rajeswary , Safiin Norhisham
Published: December 2009

Cased-hole gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels, which act as conduits between the reservoir and the wellbore for hydrocarbon production.

This project presents a system approach for removal of perforation damage, effective gravel placement, and packing of the perforation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices.

Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid (water packs). The proposed technique involves surging the perforations prior to the gravel-pack operation, followed by pumping the gravel slugs in a nondamaging carrier fluid in concentrations ranging from 1 to 3 ppa. These slugs range from 5 to 7 bbl and are pumped intermittently between stages of the completion fluid to minimize cost. The carrier fluid, by virtue of its viscosity and mechanical suspension capability, ensures that the gravel enters the perforations.

This technique was successfully implemented at the Abu Cluster field in west Malaysia. This reservoir had extremely high permeability (1.5 to 3 Darcy), with sand production a major concern. Several jobs were completed with the above mentioned technique and perforation packing factors improved from 10 to 40 lb of gravel per foot of perforations. Discussion of the placement and production data is presented. Sand-free production has been achieved with reduced drawdown across the sandface and production rates as high as 5,000 BOPD.
Optimization of Smart Wells in the St. Joseph Field
Authors: van Essen G. M. , Jansen J. D. , Brouwer D. R. , Douma S. G. , Rollett K. I. , Harris D. P.
Published: December 2009

The St. Joseph field has been on production since September 1981 under natural depletion supported by crestal gas injection. As part of a major redevelopment study the scope for water flooding was addressed using 'smart' completions with multiple inflow control valves (ICVs) in the wells to be drilled for the redevelopment. Optimal control theory was used to optimize monetary value over the remaining producing life of the field, and in particular to select the optimal number of ICVs, the optimal configuration of the perforation zones, and the optimal operational strategies for the ICVs. A gradient-based optimization technique was implemented in a reservoir simulator equipped with the adjoint functionality to compute gradients of an objective function with respect to control parameters. For computational reasons an initial optimization study was performed on a sector model, which showed promising results.
Fundamental Safe Work Practices (FSWP) Assessment through FAsT Application in Chevron-Sumatera Operations
Authors: Razi Muhammad , Afrianty Renny
Published: December 2009

As a Production-Sharing Contractor to BP MIGAS (Indonesian Government Body for Oil and Gas), PT Chevron Pacific Indonesia (CPI) - Chevron Sumatera Operations is Indonesia's largest oil producer. CPI employs approximately 6,500 people and additional 30,000 people as contractors in its operating area throughout Riau Province on the island of Sumatera.

The huge numbers of facilities around 800 are operated in CPI. It is believed that there several hazards during job activity. In managing those hazards, CPI initiated to deployed FSWP - Fundamental Safe Work Practices system since 2003. There are seven elements: Access Control, Work Permit, Personal Protective Equipment, Standard Operation Procedure/Job Safety Analysis, Lock-Out & Tag Out, Material Safety Data Sheet, and Housekeeping.

Each element consists of: definition, scope, process, infrastructure, and specific competency on process performers. One of Process performer is Facility Owner who is a leader that has a role to assess his assigned facility in monthly basis.

FAsT is an IT Application to track and trace the last status of FSWP implementation in every facility inside CPI.

This Application is intranet using network database. The users are: Data inputer, Facility Owner, General User, and administrator. Using this local web-based application is effective to see how far the FSWP implementation in all CPI facilities. Every employee has an access to generate report on the facility.
Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) for Heavy-Oil Recovery: Experimental Analysis of the Mechanism
Authors: Muatasim Al , Bahlani Al , Babadagli Tayfun
Published: December 2009

Heavy oil trapped in fractured carbonate reservoirs possesses a great challenge. Previous experience has shown that heating the matrix to drain heavy-oil by gravity is a slow and inefficient process due to low matrix recovery caused by unfavorable matrix properties (oil wetness and low permeability). Acceleration of matrix-fracture interaction by changing matrix and oil properties could be possible, however, by injecting proper hydrocarbon solvent alternately with steam as reported by our earlier work (SPE 117626). This process called Solvent-Over-Steam injection in Fractured Reservoirs (SOS-FR) consists of several cycles, each having three phases: (1) steam/hot water injection, (2) solvent injection, and (3) steam/hot water injection.

This paper reports a detailed experimental analysis of this new method. Static and dynamic tests were conducted by exposing (or injecting) heavy-oil saturated fractured rocks into steam/hot water and solvent alternately. Oil-wet sandstone and carbonate samples were saturated with heavy-crude. Different solvents were tested including heptane, kerosene, decane and light crude. In addition to the core experiments, the same procedure was repeated on "Hele-Shaw like" glass models to visually identify the mechanics of the process.

Specific observations and conclusions as to how to apply this technique in field conditions, which mechanisms control the rate of recovery and residual matrix oil saturation, ideal solvent type, and optimal operational conditions (optimal soaking time for huff-and-puff and injection rate for continuous injection) were reported. It is hoped the proposed new technique will be an alternative for tapping heavy matrix oil from oil-wet, fractured, deep, carbonate fields.
Transient Multiphase Flow Modeling of Gas Well Liquid Loading
Authors: Veeken Kees , Hu Bin , Schiferli Wouter
Published: December 2009

Gas well liquid loading occurs when gas production becomes insufficient to lift the associated liquids to surface. When that happens gas production first turns intermittent and eventually stops. Hence in depleting gas reservoirs the technical abandonment pressure and ultimate recovery are typically governed by liquid loading. To date, most methods for predicting liquid loading have followed Turner et al. (1969), which describe liquid loading as the point where the liquid droplets suspended in the gas flow start moving downward rather than upward. This paper presents (offshore) liquid loading field data that exceed the Turner predicted values by on average 40%, and analyses the sensitivity of the liquid loading gas rate for different well parameters. It subsequently presents the results of steady state and transient multiphase flow modeling, carried out to identify the influence of the same well parameters. A modified Turner expression is proposed that best fits the liquid loading field data and broadly agrees with the results of a multiphase flow model that uses a modified version of the Gray outflow correlation. The results of transient flow modeling support the flow loop observation that liquid loading occurs due to liquid film flow reversal rather than droplet flow reversal. The impact of these findings on gas well deliquification is explored.