bluuebunny/crossref_metadata_2025 huggingface dataset:
Large-Scale Application of Wet-Gas Metering at the Oman Upstream LNG Project
Authors: Konopczynski M. R. , de Leeuw H.
Published: December 2007

This paper describes the application of wet gas flow measurement to over 35 wells in the Oman Upstream LNG project. This multiphase metering process uses permanently installed wet gas Venturi meters at each well location in combination with a tracer dilution technique. Standard single phase venturi flow rate calculations are corrected for the mixed phase flow by published correlations. The tracer dilution technique, which involves the injection of suitable tracers into the flow line followed by sampling of the liquids, is applied periodically to enable the liquid to gas ratios to be determined. In the present case, wells are involved with condensate/gas ratios ranging from 350 m3/million sm3 to 800 m3/million sm3.

Unique experience has been gained in implementing the wet gas metering process in a large scale installation, including the incorporation of the wet gas Venturi correction algorithm in the DCS system, the understanding of fluid PVT behavior and its effects on the calculations, and the optimal installation of venturi, tracer injection and fluid sampling hardware. To date the technique has provided results with an error of less than 10% for the gas phase. This continues to improve as more experience is gained and empirical data is collected. This paper describes the wet gas flow rate calculations, the sample production data supporting the validity of the technique, as well as a number of practical issues to be considered before applying this technique to continuous gas/condensate metering.

The current application demonstrates that wet gas flow measurement has been applied successfully to large scale multiphase metering of individual gas/condensate wells, thereby providing continuous production data for reservoir surveillance whilst eliminating the need for expensive test separators and associated manifolds.
Quantifying the Economic Impact of 4D Seismic
Authors: Waggoner J. R.
Published: December 2007

Time-lapse 3D, or 4D, seismic has been looked at by the industry for over a decade, with a growing number of successful cases being reported in the literature. Two of the most recent 4D case studies reporting success are Draugen in the Norwegian North Sea and Gannet-C on the UK continental shelf. Both have been technical successes, providing good images of time-lapse changes in the reservoir. These 4D results have changed drilling locations and reduced the risk associated with costly field development decisions.

The focus of this paper is quantifying the economic impact of 4D seismic. After reviewing some of the ways that 4D seismic can impact reservoir management, an economic model is developed that can quantify that impact. The decision tree models use Bayes’ Theorem to compute the modified probabilities resulting from the 4D seismic. The model indicates that, for the case of drilling an infill well, 4D seismic information adds considerable value to the project, even considering that the 4D information is not perfect.
Valuing and Comparing Oil and Gas Opportunities: A Comparison of Decision Tree and Simulation Methodologies
Authors: Mudford B. S.
Published: December 2007

Decision trees have been widely used in the petroleum industry for both economic evaluation and decision analysis. In recent times Monte Carlo simulation has begun to be used to value oil and gas projects and to analyze decisions. In this presentation I will compare and contrast decision tree and simulation methodologies for both economic valuation and decision analysis. As a starting point, I will take a typical Gulf of Mexico project from exploration through to development. The results of a decision tree analysis of the project and a Monte Carlo simulation of the project will be compared. When using decision trees, the expected monetary value (EMV) is usually calculated and used to value the opportunity. Frequently the impact of uncertainties on the EMV is not assessed. In contrast, with the simulation approach the full net present value (NPV) distribution is calculated along with the risk. We will show that, for the Gulf of Mexico project, a relatively complicated decision tree is needed if the EMV of the decision tree is to be close to the mean NPV calculated using the simulation. However, even when the EMV and mean NPV are close, the additional information about the NPV distribution that is part of the simulation output enables risk to be an explicit part of the decision-making process. Although decision tree methods can be extended to include an assessment of risk, since the form of the NPV distribution is not known when using decision trees, a true assessment of project risk is not available.
Successful West Delta Block 89 Redevelopment Utilizing Re-entries and Openhole Horizontal Gravel Packing
Authors: Vozniak J. P. , Dooley W. E. , Casto R. G. , Bologna G. J. , Beal T. M. , Smejkal K. D.
Published: December 2007

The redevelopment of West Delta Block 89 consisted of two re-entry wells completed as 6 ¾ in (172 mm) openhole gravel packs with 4 in (102 mm) pre-packed screens inside 500 ft (152 m) horizontal holes. These two wells were the first application of horizontal technology for Agip Petroleum in the Gulf of Mexico and more than doubled oil production at West Delta 89, while being under planned time and budgets.

This paper will demonstrate that with open communication during the planning and execution phases between operating personnel, service companies, and contract personnel, advanced technology can be employed successfully on the first attempt. Overcoming challenges such as complex directional profiles to ensure proper placement of horizontal wells in a thin oil column between a gas cap and water aquifer, high torque and drag, formation damage, hole cleaning, and completing relatively slim holes requiring sand control are discussed. An industry milestone was achieved on the second well when a steerable rotary assembly was used to kick off the directional well in a soft formation for the first time.

The results are summarized for the wells A-9 and A-21, and expand the use of re-entry drilling technology in complex directional trajectories, and openhole horizontal gravel packing (OHGP) in relatively slim holes. Applications exist in fields requiring an alternative to cased hole gravel packing and in field redevelopment projects where perceived marginal economics exist.
Field Case Studies of Pressure Transient Data from Complex Reservoirs
Authors: Guo Boyun , Westaway Peter , Jacquemont Jerome
Published: December 2007

Modern welltest analysis and interpretation techniques rely on a match between the actual reservoir pressure response and analytical models. For many well and reservoir configurations the analytical techniques are sufficient. However, recent advances in drilling and completion technology, coupled with the increased capabilities of modern pressure gauges to detect reservoir heterogeneities, are now severely challenging the available analytical well test models. In such complicated cases numerical welltest models are frequently required. This paper reviews some field cases studied using analytical and numerical techniques with the purpose of sharing with reservoir engineers and geologists the experience we have gained from complex reservoir analyses.

Pressure transient data analyses reviewed in this paper were from three complex reservoirs: 1) a partially penetrated oil reservoir with faults and aquifer support, 2) a layered oil reservoir with a horizontal wellbore, and 3) a gas storage reservoir with internal faults. We found that analytical models were useful for reservoir model diagnosis but inadequate for delivering reliable reservoir parameters for the more complex situations. With guidance from the analytical models, numerical welltest models helped us to gain insight into the structural complexities
An Infinitely Variable Choke for Multi-Zone Intelligent Well Completions
Authors: Williamson Jim R. , Bouldin Brett , Purkis Dan
Published: December 2007

State-of-the-art completion technologies to more efficiently support the needs of the oilfield continue to be developed. For example, intelligent completion techniques, which are designed to allow the operator to reconfigure well architecture without well intervention, have gained a great deal of attention because of their capabilities to improve monitoring and overall well performance in multi-zone oil and gas field developments. In all of these multi-zone intelligent-well completions, flow adjusting and monitoring devices or interval control valves are located between zonal isolation packers to control flow into or out of each zone.

The first generation of these interval control valves was a choke that offered only four positions. To overcome the position limitations, an infinitely variable choke has now been designed. The requirements for this next-generation interval control valve provided many design challenges. This paper describes the design, development and testing of a metal-to-metal sealing, infinitely variable downhole choke with true position sensing capability. All topics from the conceptual design and customer requirements to accelerated erosion testing and component life predictions will be discussed. Testing has verified that the new interval control valve can support the needs of the multi-zone well completion. This new technology has been installed in a Statoil water injection well.
Low Cost Horizontal Well Design and Implementation: A Case Study from the Kenmore Oil Field, Eromanga Basin
Authors: Hedger L. K. , Lansom P. B. , Trethowan E. , Anthony D. P. , Arnold A. , Gillibrand J.
Published: December 2007

This paper describes an unusual well design that has been implemented in a mature onshore oil field to minimise the cost of development drilling, improve well performance and utilise existing infrastructure. Horizontal wells were proposed to maximise oil recovery from the thin remaining oil column in the Kenmore Field, which has a strong bottom water drive. The challenge was to design horizontal wells that cost no more than low cost vertical wells. The drilling project was completed in January 2000, with the lessons learnt widely applicable.
Foam Properties Requirements for Proper Hole Cleaning While Drilling Horizontal Wells in Underbalanced Conditions
Authors: Martins A. L. , Lourenço A. M. F. , de Sá C. H. M.
Published: December 2007

This paper summarizes an extensive experimental program developed at PETROBRAS R&D Center, as part of the JIP named "Lightweight Fluid Drilling from Floating Platforms". The lab work steps include foaming agent selection (considering optimum concentration and salt/oil contaminants), rheological characterization of foams, development of a flow loop to test foam carrying capacity in high angle wells, definition of test procedure and matrix, besides discussion and analysis of results. Besides, based on results obtained from a numerical simulator, a comprehensive and useful model for predicting hole cleaning while drilling under-balanced or near balance with foams is proposed. After about 50 bed tests performed in PETROBRAS cuttings transport flow loop, correlations were proposed to predict cuttings bed erosion capacity in horizontal wells as functions of foam quality. Based on the experiments and on a mechanistic model for cuttings transport, foam rheology and stability requirements for drilling vertical, inclined and horizontal wells in underbalanced and near balance conditions were established.
A 3-D Numerical Model for Designing and Planning of Matrix Acid Stimulation in Low-Permeability Rocks
Authors: Chen Zhixi , Nguyen Desmond , Rahman Sheik S.
Published: December 2007

Based on material balance and theory of surface reaction kinetics in porous media, a 3-D numerical model was developed to predict changes in rock properties due to acid stimulation. The simulator were then verified with experimental results from acidizing test conducted on core samples taken from a number of reservoir rocks. It was found that the simulator could adequately predict spent-acid concentration and changes in porosity and permeability as a function of penetration depth for given acid treatment conditions. We also demonstrated how the numerical model could be used to design and plan acid stimulation work for given reservoir conditions.
Fracture Porosity from Conventional Logs with Image Tool Calibration
Authors: Adams S. J.
Published: December 2007

Petrophysical evaluation of the Moki Formation in the Toka-1 exploration well, required rapid quantification of fracture porosities, enabling likely hydrocarbon volumes to be estimated. A resistivity imaging tool had been run over the approximately 400m of fractured interval. This information was being processed for fracture apertures by the acquisition contractor, but the rate of quantification was too slow to meet the operators objectives. A technique was developed to rapidly estimate fracture porosities using the difference between the density and the compressional sonic porosities and the difference between the shear and compressional sonic porosities. The fracture porosity estimates were cross-checked against the image log analysis completed. Owing to washouts across the most heavily fractured intervals, it was expected that fracture porosities from the density and compressional sonic logs were maximum values. The most likely fracture porosities were thought to be those derived using the shear and compressional velocities. The fracture porosities estimated by hand-picking fractures from the image data were considered the minimum values, since the identification process was incomplete. The work described represents a new technique for fracture porosity quantification. The comparison with image log interpretation over a short interval gives confidence in the methodology. The results are significant in that they show rapid quantification of fracture porosity is possible by using conventionally acquired logs, although it should be recognised that the uncertainty in this approach is significant. Application of this technique to other fields with limited image data may prove helpful in reservoir modelling and understanding of production behaviour.
The Stuart Oil Shale Project
Authors: McFarland J. D. , Hopkins P. D.
Published: December 2007

The A$250 million Stuart Stage 1 Oil Shale Project in Queensland, Australia is one of the most significant new developments in the non-conventional oil industry. The Stuart Project is a joint venture between Australian companies Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM), and Canada's Suncor Energy Inc. (Suncor). An important milestone was reached in 1999 with completion of construction of the Stuart Stage 1 technology demonstration plant. This 4,500 b/d (715 m3/d) plant, constructed by Bechtel, is currently being commissioned by Suncor, the project operator.

The Stuart oil shale deposit has an estimated in situ resource of 3 billion barrels of shale oil. The Stuart Project incorporates the Alberta-Taciuk Processor (ATP), a new generation of oil-shale retorting technology which was chosen following a A$150 million R&D program in the 1980s. Upon technical and operational success in Stage 1, the next step is to scale up the ATP in Stage 2 to a commercial sized module producing 15,000 b/d (2,350 m3/d). This could lead to a commercial scale operation of at least 85,000 b/d (13,500 m3/d).

Success at Stuart will have important implications for Australia in terms of job creation and development of a new source of indigenous oil supply. It could also be important for world oil supply given the immense size of the world's oil shale resource.
Reservoir Management and Discovery of ‘New’ Oil in an ‘Old Field’: A Case Study
Authors: Rajkhowa Anupam , Jena Sampad K. , Ravichandran V.
Published: December 2007

The Moran oilfield is one of the oldest oilfields of the Upper Assam basin, which is a part of the Assam-Arakan geological province. This field located in northeastern India, has been on production since late fifties from clastic sandstone reservoirs of Barail group of Oligocene age. The reservoirs deposited in fluvio-deltaic environment, occur as multi-stacked channel sands in a depth range of 3200-3600 m. Recovery so far from these reservoirs has been around 29% of OOIP and the field is currently producing 350 cum/day of oil as against a peak plateau production rate of about 2500 cum/day. The case history describes reservoir management of the field and highlights success of recent exploration in terms of discovery of deeper oil prospects in the field. Commercial discovery of ‘New’ oil in the ‘Old’ field in the very first exploratory well has raised prospects for better utilisation of existing infrastructure facilities.

In order to accurately define the sand channel geometry, supplement ongoing reservoir management measures in the producing Oligocene reservoirs, and also to explore the deeper Eocene prospects, 3D seismic has been acquired during 1998. The 3D seismic data integrated with a large number of Oligocene well evidence has resulted in refinement of the sand channel geometry and identification of fairly large structures at Lower Eocene level. Oil has been discovered in the very first test well drilled on the deeper Lower Eocene structure within Lakadong member of Sylhet formation at a depth of about 4650 m. The discovery of this new hydrocarbon play has resulted in additional reserve growth of significant potential. Plans are in hand for development of Moran field for Lower Eocene prospects simultaneously with enhancing recovery from shallower Oligocene reservoirs.
Trunklines on Rugged Seabeds - Application of Technology to Quantify and Reduce Costs
Authors: Fogliani A. J. , Smith N.T. G.
Published: December 2007

The high cost of constructing and maintaining a large offshore pipeline system over rugged seafloors means that particular attention is required to achieve an accurate cost estimate and an economic design. In many cases the feasibility of a field development will be revisited as technology catches up with the specific requirements of the project. Advances in survey equipment, digital terrain modelling of three dimensional bathymetric data and the integration of spanning analysis models allows the engineer to optimise route selection, minimise high cost intervention works and more reliably estimate project costs.

This paper identifies and reviews the key cost drivers of strategic trunkline projects, the implications of rugged seabed features and the benefits of route optimisation technology. The paper outlines methods for the implementation of route optimisation technology and particularly addresses the interactive application of the technology during the survey works. The benefits of teamwork and interaction between the survey team and the pipeline engineering team are highlighted. This paper includes a list of applications and also outlines proposed future development of the technology.
Overcoming Completion Challenges with Interventionless Devices - Case Histories of the "Disappearing Plug"
Authors: Larimore David R. , Huggins Jeff , Robb Ewan , Ching Willie , Thomson D. W. , Jennings John , Bach Terje
Published: December 2007

The ongoing need for greater operational cost efficiency has encouraged oil companies to seek new methods that can simplify completion processes and reduce the number of required well interventions. This focus has resulted in new challenges for engineering/manufacturing and service companies to develop multi-functional equipment. To meet these challenges, a new generation of completion equipment with capabilities that would have been considered impossible ten years ago has been introduced to the oilfield. This equipment has been designed to not only reduce the number of interventions normally required in traditional completion scenarios but also to meet challenges of safety and reliability that can surpass the cost of contingency measures should the product fail.

The development of one such device, the "disappearing plug," which serves as a plugging device for setting a hydraulic-type packer, will be the focus of this paper. When run in with the completion, the tubing will fill automatically through an auto-fill device, and then, will close during one of the pressure cycles. The fluid-expendable plug material disintegrates on the last pressure cycle, which allows full- tubing-drift production and eliminates the need for a slickline or coiled-tubing run to retrieve a plugging device as would be the case with conventional methods.

While the industry average for successful installation of interventionless devices has still not reached the sought-after 100% reliability, when these concepts have been successful, the expected economic job goals have been surpassed. When successful in offshore, horizontal, and/or high angle wells where slickline or coiled tubing intervention after completion is significantly more costly, these interventionless technologies have proven to be even more beneficial.

The paper will discuss development of the plug, some of the failures that occurred, how these difficulties were addressed, and finally, will discuss several recently run installations. These clearly show the extent of the economic benefit that can be realized.

Disappearing plug technology currently improves economics by eliminating the need for slickline and coiled- tubing interventions in plugging operations. When setting hydraulic packers, this not only reduces operating costs but also the risks associated with interventions and plug failures. One of its most significant contributions, however, becomes apparent when considering the future trends of the industry — interventionless and intelligent well technologies. The disappearing plug will undoubtedly play an important role in the actualization of these future well trends.
The Application of Modern High Quality and High Speed Drilling Technology in SZ36-1 Oil Field Development of Phase II in Bohai
Authors: Wei Jiang
Published: December 2007

This paper mainly describes the application of modern high quality and high speed drilling technology in SZ36–1 oil field development and construction of phase II, and summarizes the innovation spirit and achievement during the project. The drilling project had highlights as follows. Firstly, the distribution of cluster wells becomes denser. The distance between wells had been reduced from 2m%2m to 1.5m%1.8m. Secondly, the number of wells in platform was more than 35 wells and the controlling oil reservoir area had increased more than two times. Finally, the quality and efficiency of drilling operation has achieved new level. The drilling operation of three wellhead platforms with three platforms spent 246 days of drill platform. The total numbers were 78 wells and footages were 149946m. The average depth per well was 1922m and average operation period is 3.15 days per well. The quality of all wells is perfect. During the operation, broke through four records of China National Offshore Oil Corporation (CNOOC) in production well ten times and create 1.61 days new record that is the shortest operation period. Compared with the other wells, the drilling efficiency and operation period reached the best level of CNOOC. It provided helpful suggestions and experiences for the future development and construction of oil field.
Geological Knowledge Data-base of Fan-delta
Authors: Jia Ailin , Mu Longxin , Huang Shiyan , Chen Liang , Zhang Chuanlan
Published: December 2007

In the period of maturing oil field development, on one hand, water saturation becomes higher and higher, on the other hand, lots of moveable oil still stays in the reservoir. The main reason for this case is determined by the variation of the reservoir, so the main job for geologists is to know the heterogeneity and continuity of the reservoir. In this case, the well spaces are about 200-300 meters. In order to give a relatively reliable prediction of the reservoir variation between wells, we must build a prototype model and know the real condition of the reservoir. During the past 5 years, we have studied the fan-delta outcrop and built a very detailed prototype model and established sets of geological knowledge databases, which include lithology database, microfacies database, sandbody scale database and many geological statistic databases.

According to these useful databases, we can predict the heterogeneity and oil saturation of maturing oilfield in different blocks and different layers. A few wells have been drilled according to our prediction through prototype model, and the oil saturation is 5-7 times higher than the old wells. Prototype model is very useful in the oilfield reservoir heterogeneity prediction, which have the same or similar depositional environment. In order to predict the reservoir variation of different depositional reservoir, series of prototype models must be built.
Experimental Study on Friction Pressure Drop for NonNewtonian Drilling Fluids in Pipe and Annular Flow
Authors: Subramanian R. , Oklahoma Tulsa , Azar J. J.
Published: December 2007

An extensive experimental study on friction pressure drop for nonNewtonian drilling fluids in pipe and annular flow was conducted. A fully instrumented 350 feet flow loop, consisting of two pipes and two annular flow test sections, was used in the test program. Five different muds were tested, which included: Bentonite mud, MMH mud, polymer mud, Glycol mud and Petrofree vegetable oil mud.

The experimental data obtained were used to generate very useful plots of "friction factor" versus "generalized Reynolds number". For each of the mud systems, the plots offer a practical and accurate means in determining needed friction factors for the calculation of pressure drops in pipe and annular flow. In addition, a comparative discussion is presented on measured friction pressure drop data, predicted by correlations such as the power law, Bingham plastic and yield power law. The importance of wall roughness on turbulent flow friction pressure drop calculations is also investigated.
Screening Variables for Multilateral Technology
Authors: Brister Ray
Published: December 2007

The multilateral well was one of the leading technologies of 1999, and it will continue to be one of the leading technologies for the next 5-10 years. It is likely that because of the cost reduction driver, management will ask, "Why isn't this a multilateral well?" much like the current justification for horizontal wells. The two challenges in 2000-01, unmet in 1999, will be consistent success of the technology and the low cost multilateral.

When evaluating multilateral technology, it is important to understand three things. First, in its simplistic scenario, the only difference between a multilateral well and a sidetrack or redrill is that the original wellbore will remain open when placed on production. The second thing to note is that multilateral technology is a reservoir development technology rather than a drilling technology. The drilling department is simply the vehicle by which this reservoir technology is brought to fruition. And third, all major operating companies will utilize multilateral technology; the question of consequence is ‘when?’.

The purpose of this paper is to present the first steps in applying multilateral technology to the operator in a practical way. This paper will cover only one aspect of multilateral technology – screening variables. These screening variables should be viewed as fundamental criteria from which, to begin a multilateral feasibility study. One of the screening variables is the driver for multilateral technology. Since the business driver must be evaluated before any other screening variable, it will be covered first. The remaining variables will be covered according to the order in which they appear in the planning, design, and implementation of a multilateral project. The completion variables will be specified first, followed by reservoir and geological screening variables.

Finally, drilling and other general screening variables will be covered. Discussion of the different classifications or levels of multilaterals is taken from the TAML (Technical Advancement of Multilaterals) Classification system (Chambers1, Mackenzie and Hogg2).
Guidelines for Efficient Spot Fluid Displacement in Highly Inclined and Horizontal Wells
Authors: Martins A. L. , Sansoni U. , de Camargo J. W. , de Oliveira S. F.
Published: December 2007

Differential pipe sticking is still today a challenging problem in horizontal well drilling. The main focus of this paper is the analysis of the dynamics of substitution of a viscous fluid (the drilling fluid) by a less viscous one (the spot fluid) in a fully eccentric horizontal annulus. Initially, an experimental study aiming the determination of the flow rates required for the substitution was performed on a pilot scale flow loop using flow visualization techniques. The tests reproduced the drilling of 8½ in horizontal wells. An extra test was performed to reproduce the 12¼ in phase. Based on results obtained from a 2D simulator predicting the critical shear stresses in horizontal eccentric annular flows, a mechanism for the efficient displacement of spot fluids is proposed.
The Pilot Test of ASP Combination Flooding in Karamay Oil Field
Authors: Qi Qiao , Gu Hongjun , Li Dongwen , Dong Ling
Published: December 2007

The chemical screening and chemical formulation studies were discussed in this paper, and the pilot test results as well for the ASP combination flooding pilot test in Karamay EZ District. Also the designing strategies of the ASP process were included in this paper. The ASP pilot test started from August 21,1995 with the beginning of NaCl brine pre-flush in order to condition the reservoir, then followed by ASP slug and Polymer slug. The post-water injection was applied after the designed chemical injections. The 24%OOIP incremental oil recovery was achieved in the whole test area with about 25%OOIP incremental oil recovery for the central production well.
Economic Evaluation of Enhanced Oil Recovery
Authors: Zekri Abdulrazag Y. , Jerbi K. K. , El-Honi Mohamed
Published: December 2007

The research for tomorrow's oil reserves has directed the efforts of the energy industry to frontiers beyond the conventional exploration and production strategies. Frontier defined not by geography or geology but rather by technology. This frontier is a collection of technologies-involving the use of thermal, gas and chemical means for producing more oil-that fall under the broad umbrella called Enhanced Oil Recovery (EOR). The results of successful application of this new technology will have a decisive impact on the energy conservation program of any oil producing country.

A comprehensive national energy program is complex and to plan it represents a challenge. A unified and complete national program must encompass the consideration of all possible options. The potential of each need to be explored. One such option in Libya is to produce more oil, that is, to effect the enhancement of oil recovery from the nation oil fields. The planning of an EOR project demands a meticulous attention to many problems, thus requiring considerable lead time for studies, evaluations, project design and most of all the economics of these high cost EOR projects.

The objective of this study is to conduct an economic analysis on one of the most representative candidate major field in Libya (D field) for application of the technically approved Enhanced Oil Recovery methods. By performing economic sensitivity analysis on key input variables such as oil prices, the price of injection solvent, capital expenditures, operating expenses, and oil recovery with the aim to develop sensitivity analysis graphs for each variable to assess future engineering planning with regard to the EOR projects economics in Libya. Economic optimisation is the ultimate goal of reservoir engineering management. With estimated production, capital, operating expenses, and financial data, project economics are evaluated. Project finding could be applied to any EOR candidate reservoir worldwide.
Case Studies on Application of Novel Guideline Charts in Planning Well Trajectory and Mud Weight Program
Authors: Chen X. , Tan C. P. , Haberfield C. M.
Published: December 2007

Wellbore instability remains an important and costly issue in many oil and gas fields. Field observations have shown that stress-related wellbore instability problems are still frequently encountered even though techniques to manage the problems have been adopted. The problems can be a main factor in reducing the benefits of introducing innovative drilling technology.

This paper describes the methodology and procedures for determination of optimum wellbore profile and mud weight program based on rock mechanics considerations. The comprehensive methodology, covering all key aspects of wellbore instability, is presented in the form of guideline charts. The application of the methodology and procedure is described and demonstrated through three field case studies for a range of in-situ stress regimes in various parts of the world.
Sand Production Simulation in Heavy Oil Reservoirs
Authors: Zhang Liangwen , Dusseault Maurice B.
Published: December 2007

A new sand production model is developed based on inter-particle contact force variations at the discrete micromechanical level. Two mechanisms for sand production can be expected in the field, dynamic detachment and equilibrium yield. The model discussed in the paper describes the sand production mechanism in the dynamic detachment process. Within the new model formulation, sand is considered to be produced because of either a large porosity gradient or a large pressure gradient. The 1-D steady-state solution of the new model is also presented; it may be used for simple sensitivity analysis for parameters such as the field stress and pressure depletion effect.
Application and Development of Drilling and Completion of the Ultrashort-Radius Radial Well by High Pressure Jet Flow Techniques
Authors: Li Yonghe , Wang Chunjie , Shi Lianhai , Guo Weiyi
Published: December 2007

Ultrashort radius radial well drilling and completion technique by high pressure jet flow is referred to as the Ultrashort radius (0.3meter) radial horizontal well drilling and completion techniques. It can be applied both in new and old wells. Its main technique is to use high pressure jet flow energy, given by a special high pressure jet tube, to penetrate and elongate a number of lateral well bores radiated from the main well bore in the same layer (or different layer) so as to expose the pay zone as much as possible and increases the EOR.

This paper has described three key parts of high pressure jet flow technique for ultrashort radius radial well drilling and completion: big diameter underreaming technique; design principle of diverting system; and option of well completion methods. And introduces whole process and key parts of this technique combined with its application results in Jin Well#04–19 and Jin Well#38–303 of Liaohe Oilfield. This paper has also briefly depicted the future development of this technique in the Oilfield and its main problems must be resolved later, as well as its economy and feasibility.
Minimize Sand Production by Controlling Wellbore Geometry and Flow Rate
Authors: Samsuri A. , Chuong P. V.
Published: December 2007

The production of sand particle has become serious problem to oil and gas well and was subject for study during the past years. Basically, sand production must be the results of a change in strength of the formation rock due to drilling, perforation and production operation and drag forces of the produced fluids. Therefore, during designing and developing stages, parameters related to sand production need to be examined carefully. This paper presents an experimental study of the effects of wellbore geometry and flow rate to sand production and total oil recovery; to minimize sand production as well as optimize production. The experimental works include of static and dynamic sand production tests, which were carried out on wellbore models with different wellbore angle, perforation shot density, and perforation pattern and flow rate using Servo Control Compression Testing Machine (SCCTM). The results show that oil production is reduced as sand production increases and most of produced sand are large size indicating the dominant effects of the breakage of cementing materials. Sand production increases significantly after effective stress reaches 35–60% of rock compressive strength and followed by the reduction of total oil recovery to 55–73%. In addition, sand production increases as wellbore angle, shot density, flow rate increase and as perforation pattern change from spiral to inplane and finally inline, especially for model with more than 10° well bore angle, inline pattern and 1600cc/h flow rate. Therefore, in order to optimize production, sand production must be minimized by reducing wellbore angle (<10°), shot density, flow rate (<1600cc/h), perforated with spiral pattern and pore pressure should be controlled so that effective stress around a wellbore is not more than 35% of rock compressive strength.
A Feasibility Study of Time-Lapse [4D] Seismic Monitoring of Water Injection Recovery Processes
Authors: Zhou Chengdang , Liu Wenlin , Chen Shuzhen , Li Fanhua
Published: December 2007

Water injection is the most commonly deployed recovery method in most Chinese oilfields. Efficiently monitoring production behavior in the water injection recovery processes is essential to improving water injection efficiency and enhancing oil recovery. Currently, time-lapse seismic reservoir monitoring(TLSRM) is widely used in reservoir monitoring. However, only the reservoirs whose seismic response changes caused by their internal fluid changes are large enough, compared with seismic noise, are suitable for time-lapse seismic surveys. So it is necessary to do a feasibility study of time-lapse seismic before starting a time-lapse seismic survey. Fluvial and delta facies reservoirs are the primary depositional facies types. In this paper, a numerical reservoir simulator is used to simulate the fluid flows in the water injection recovery process in a fluvial reservoir, and Gassman's equation is used to generate synthetic seismograms corresponding to different recovery time. By analyzing velocity and impedance differences between synthetic seismograms of different production time with reservoir physical parameters, the feasibility of TLSRM of the water injection recovery process of the interested reservoir is studied.

Introduction

Water injection is the most commonly deployed recovery method in most Chinese oilfields. Production in the water-injection oilfields can be divided into three stages: primary production, stable production and descreasing production stages. Since the reservoir recovery time without water-injection is short, recovery with high water cut is the main stage in the reservoir recovery process. And the main method maintaining production in the high water-cut period is the proper adjustment of oil recovery projects. Efficiently monitoring production behavior in the water injection recovery processes is essential to proper adjustment of recovery projects, improving water injection efficiency and enhancing oil recovery. Both fluid production and injection in the recovery processes will result in changes of reservoir physical properties which, in turn, lead to changes of the associated seismic properties and responses. Through analysis and comparison of seismic data repeatedly acquired at different time at the same place, time-lapse seismic can visually indicate the changes of reservoir physical properties in the recovery processes, realizing monitoring of dynamical behavior of recovery processes. However, only the reservoirs whose seismic response changes caused by their internal fluid changes are large enough, compared with seismic noise, are suitable for time-lapse seismic surveys. So it is necessary to do a feasibility study of TLSRM before starting a time-lapse seismic survey.
Bridging Adsorption of Cationic Polyacrylamides in Porous Media
Authors: Denys K. , Fichen C. , Zaitoun A.
Published: December 2007

Recently, cationic polyacrylamides (CPAM) have been successfully applied in water shutoff treatments of oil and gas wells. These polymers adsorb strongly on reservoir rocks, building up an adsorbed layer of significant thickness. Moreover, under high rates, the coiled macromolecules stretch and can bridge large pore throats. This so-called bridging adsorption mechanism has been described previously for high-molecular-weight non-ionic polyacrylamides (PAM).

CPAM rheology and retention behavior has been studied in unconsolidated SiC packs and in Berea sandstones in a permeability range 0.1-1 D with CPAM solutions having a cationicity between 0 and 50%. Due to the attraction between the positive charges carried by the polymer chain and the negative surface charges of the rock, both CPAM adsorption and bridging adsorption are higher than for PAM having the same molecular weight. A maximum adsorption is found around 10-15% cationicity. This maximum, observed both in SiC and in Berea, is due to the competition between adsorption energy and pore wall accessibility. Although the permeability to water drops considerably after CPAM bridging adsorption, the permeability to oil is remarkably preserved, which makes CPAM attractive for water shutoff applications.
Modeling Acid Returns Profiles After HF Acidizing Treatments
Authors: Gdanski Rick
Published: December 2007

A comprehensive HF (hydrofluoric acid) acidizing radial-flow model has been modified to accommodate deep-matrix mixing and backproduction of spent acidizing fluids. The model has successfully matched the published ionic returns profiles of several HF acidizing treatments. The model was used to demonstrate the magnitude of fluid mixing within the matrix. It was shown that approximately two treatment volumes of aqueous production are required to recover most of the original treating fluid. The impact of mixing and ion exchange on lowering produced fluid pH long-term after acidizing treatments was also demonstrated. A hypothetical HF acidizing treatment was modeled and used to demonstrate the ionic profiles within the matrix that result from the various reactions and precipitations. The ionic profiles that would be observed in spent-acid returns were then modeled to provide a general view of typical returns compositions. Field acid returns were matched with the simulator, and they demonstrated that information about formation mineralogy and reaction kinetics can be obtained.
Novel Application of Synergistic Guar/Non-Acetylated Xanthan Gum Mixtures in Hydraulic Fracturing
Authors: Fischer C. C. , Navarrete R. C. , Constien V. G. , Coffey M. D. , Asadi M.
Published: December 2007

Fracturing fluids have traditionally been viscosified with guar and guar derivatives. Non-acetylated xanthan is a variant of xanthan gum which when combined with guar in solution develops a synergistic interaction that generates superior viscosity and particle transport at low polymer concentrations. These water-base linear fluids have improved low shear viscosity at concentrations at or below 25 lb/1,000gal when compared to fluids viscosified using a single viscosifier such as guar or xanthan gum. The polymer mixtures can be crosslinked to provide enhanced viscosity at higher temperatures.
Hydraulic Fracturing Treatments In The Buena Vista Hills Field
Authors: Erickson J.B. , Kumataka M.K.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Several fracture treatment designs have been tested in the Buena Vista Hills Field in order to determine the most desirable program. Field experience and laboratory analyses show that untreated lease oil is more successful than other fracturing fluids. Current treatment methods are more effective than earlier techniques in controlling sand production and reducing rapid production decline rates. Recent stimulation efforts are economically successful and have encouraged further development of the field.

Introduction

Two low permeability sand formations in the Buena Vista Hills Field contain large amounts of oil-in-place, but primary recovery is less than satisfactory. Since 1964, fracture treatments have been performed in these zones to improve recovery, with varied results depending upon field location and treatment design. Programs using both water-base and oil-base fracturing fluids in gelled and ungelled solutions have been tested. The ungelled lease oil treatments have shown favorable response in specific areas of the field. None of the water-base fluid treatments have been successful.

The current fracture stimulation programs have evolved through a combination of field experience and reservoir analysis. Based upon past experience, ungelled lease oil is exclusively used in these programs. A few changes have been made concerning the size and amount of frac sand, and the results have been encouraging. Recent treatments appear to show slower decline rates than earlier treatments, and the problem of sand production following some of the early treatments has been eliminated. Currently a typical fracture treatment consists of 200,000 pounds of frac sand (75% 50x70 and 25% 8x12) in 50,000 gallons of untreated, 26 deg. API lease oil. The increase in production after frac oil recovery averages 25 BOPD and 150 MCFPD, which pays out the treatment in approximately two months.

This paper presents a history of fracture treatments performed in the Buena Vista Hills Field, and discusses the development and sults of various treatment designs.

GEOLOGY AND RESERVOIR DATA

The Buena Vista Hills Field is located near the southwestern edge of the San Joaquin Valley, about 45 miles southwest of Bakers-field, California.
A Technique to Estimate EOR Production from Routine Oil Samples
Authors: Moulds T. P. , Riggert V. L. , Lee S. T.
Published: December 2007

A method is presented which calculates EOR oil rate using compositional data from the produced oil stream together with a reservoir fluid equation of state. The method uses the produced oil composition to calculate molar volume and then interprets the molar volume signature in the context of reservoir geology and flow dynamics. This leads to a quantitative estimate of EOR oil volume and qualitative insight to the MI sweep pattern.

The method is extended to use API gravity input rather than molar volume. The results are equally good when using API gravity. Routine sampling for API gravity is relatively cheap so this opens the possibility of a cost effective method to directly measure EOR oil. The potential of this method is to greatly enhance the quality of information concerning flood performance so enabling more effective flood management.

The method is illustrated using several fine grid simulation models with widely varied reservoir descriptions which were built to evaluate the Prudhoe Bay Miscible Gas Project. In all cases, the EOR oil production from molar volume or API gravity analysis is within about 1% OIIP of the EOR recovery estimated from separate waterflood and WAG simulations.
Integrated Reservoir and Production Management: Solutions and Field Examples
Authors: Bøe Arild , Nordtvedt Jan-Erik , Schmidt Harald S.
Published: December 2007

Reservoir and production monitoring and control devices are critical components for better reservoir management. These devices being important for understanding the state of the reservoir as well as for optimizing its exploitation, their availability and utilization has grown and is still growing. Also, the increasing use of topside/subsea metering systems provides important information on the production characteristics. All these devices can now be logged and controlled remotely in real time. As a consequence, it is now technically possible to manage the reservoir exploitation process fully automatically from a remote location. This paper outlines how logging of data, analysis of data, and control actions, can be implemented remotely and in real time for improving reservoir and production management. Also, we discuss three integrated reservoir and production management field case designs.