bluuebunny/crossref_metadata_2025 huggingface dataset:
Solid Expandable Tubulars Slim Well Design and Isolate Zones for Brownfield Redevelopment in Oman
Authors: Morrison W. , Sanders T. , Leuranguer C.
Published: December 2007

The Fahud water flood project is a major brownfield redevelopment project and a key component to PDO's future production plan. Key value drivers for the successful project delivery are selecting the right recovery mechanisms for the target reservoirs and achieving low-cost well delivery through standardization and technological innovations.

The pilot program, which consists of drilling 39 vertical wells in PDO's Fahud field, commenced in April 2004 to gather data on four Natih target reservoirs. The data will be used to identify applicable recovery mechanisms for future field development. The recovery methods under review include the following: Water floodGas-oil gravity drainage (GOGD)Combination GOGD and water floodCombination GOGD and depletionCombination GOGD and gas flood

Natih is a stacked layered reservoir. Natih A and C were developed by water floods in 1972–1980. These wells were unsuccessful due to early water breakthrough through fractures and karst parts of the reservoir. From 1984 to 1998 certain reservoir sections were developed by GOGD with 200+ development wells drilled. Since 1997, water flooding has been used to produce different zones in the Natih reservoir. Most of the drilling during this time consisted of horizontal wells with single or dual laterals.

Although horizontal wells, in particular dual-lateral wells, provide excellent area data coverage, they also Provide ambiguous production data from single zones.Do not allow observation of reservoir behaviour in over-and underlying zones.Are costly to enter (hoist/coiled tubing).Present a challenge to manage flow profiles.

These issues led to the consideration of implementing alternative well designs.

This paper will discuss the well planning, wellbore preparation and successful application of solid expandable tubular technology. These systems, combined with swelling elastomers, slim the well design and provide reliable isolation of the Natih sub-units to allow independent testing of the zones. The paper also presents the completion design planned for the test program and long term production.
Recent Material and Geometrical Changes in Impreg Technology on Turbine Drive Lead to Reduced Drilling Costs in Hard Rock Application
Authors: Heywood C. , Currie A. , Robson D. , Casey P.
Published: December 2007

Oman's principal LNG producer is Petroleum Development Oman and their largest producing field is the Saih Rawl Field. Rigs are currently drilling in the reservoir section on the Saih Rawl Field as part the development activity on this field. The Saih Rawl Field is an important producer of the Sultanate of Oman's gas reserves. These deep gas wells have an average TD of 5000m. The reservoir zones are in Barik and Miqrat sandstones at 4500 and 4900m TVD, respectively.

The formations in the 8-3/8" section are made up of sandstone, siltstone, shale and dolomite. The Barik, Al Bashair, Miqrat and Amin formations in the 8-3/8" section are extremely hard (up to 30,000 psi unconfined compressive strength - UCCS) and abrasive. These difficult formations have traditionally been drilled with a mixture of roller cone and turbine driven impregnated diamond bits. The roller cone bits deployed in the past lacked durability. The initial impregnated bits faced ROP, durability and float equipment drill-out challenges.

Six years of material research, development, and testing on impregnated bit materials has culminated in a 260% increase in durability and a 5% increase in ROP in these formations during the past year using innovative new impregnated diamond bit designs. In addition new cutting structures and innovative bit head geometries for drill out of float equipment have allowed consistent successful drill out of the 9-5/8" shoe track displacing the use of rock bits in this application. Together these advances have reduced the time taken to drill the 8 3/8" section by an average of 10 days. This has results in an average cost saving of $430,000USD in time and materials in the 8 3/8" section. These performance advances have contributed significantly to the reduction in average well drilling time from 90 days in 2004 to 68 days in 2005.

These developments in impregnated bit technology have been extended to applications in Saudi Arabia, Algeria, Syria and Venezuela.
Application of a Light Rig in Deep Exploration Drilling Operations in Nigeria
Authors: Okwa H. , Azoom I. , Omini E.
Published: December 2007

The upsurge in drilling activities in 2004, occasioned by the strong oil prices resulted in a challenging rig market situation such that operators have to plan well in advance to be able to get a rig for the next well campaign. For desperate operators, the only option is innovation or new technology and unusual risk taking.

An operator in Nigeria recently adapted a light work over rig of 800 horsepower and 320,000lbs pulling capacity to drill an exploration to 11,000 ft. This was operating the rig at beyond its capacity.

Minor modifications were made to the rig to enable the running of casing strings, and operations monitored with the help of wells software, resulting in the successful drilling and abandonment of the A-1x well. The result was a 30% savings of the budget well cost contributed mainly from the slimmer design and lower rig rates of the light 800 hp rig. It is also noted that the light rig was moved in 8 days compared to 23 days planned with the heavier rig.

The paper highlights the detailed planning and execution of the drilling phase of the A-1x well and how the capacity issues were addressed leading to the estimated savings of $2million.
Gas Injection Programs in PERTAMINA West Java to Obtain Better Recovery: Field Screening, Laboratory and a Simulation Study
Authors: Gunadi B. , Suarana I. P. , Marhaendrajana T.
Published: December 2007

Most of oil fields managed by PT PERTAMINA (PERSERO) are considered as brownfields and the oil produced only from primary recovery stage. To get better recovery of oil in those brown fields, it is necessary to have a long term project such as Enhanced Oil Recovery (EOR). Some screening criteria had been completed to select appropriate method which could be applied in certain field. In this study, we present gas injection program in West Java to obtain better recovery of the mature field/brownfield. The gas injection program include natural gas such as ethane, propane and CO2 flooding.

The viability relates mainly to the availability of CO2, the structure complexity, and finally the achievement of the Minimum Miscible Pressure (MMP). In the Jatibarang Field, it is not an issue of gas and CO2 availability since gas and CO2 sources are available in the field itself, and near by fields.

The Jatibarang Field primary recovery is only 16.2%, and the current reservoir pressure is as low as 500 psia. The reservoir performance shows the driving mechanism in this zone is very weak water influx. Therefore a Waterflood and/or EOR Program need to be evaluated to increase oil recovery.

Based on the screening criteria for oil fields in West Java, there are several possible CO2 flood candidates, one of which is the Jatibarang Field. A fluid compatibility test was conducted using Jatibarang Field fluids, from current to initial conditions. The fluid properties of current and initial conditions were compared and analyzed using numerical simulation. Then an appropriate fluid model was selected to represent the reservoir conditions. Regression and fine-tuning of the equation of state resulted in the fluid characterization for this study. Tuning of the EOS should give a fluid model that closely matches the lab test results.

Reservoir pressure is very important when it comes to designing gas and CO2 floods, as it is usually far below the MMP, as was the case in the Jatibarang Field. Based on the fine tuned fluid model, several gas and CO2 processes (immiscible and miscible flooding) were evaluated for the Jatibarang Field. These also included evaluation of different compositions of the natural gas and CO2 gas.

The best tuning of EOS will give the fluid model that closely matches the lab test results. and then the fluid is applied to the compositional reservoir simulation. More than 25 alternatives of gas injection is studied using the compositional simulation. The best recovery is combination of water injection, CO2, ethane and propane flooding (% incremental oil recovery).
World's First MRC Window Exits Out of Solid Expandable Open-hole Liner in the Shaybah Field, Saudi Arabia
Authors: Al-Jeffre A. M. , Al-Dossary A. S. , Zhou S. , Al-Hajji A. A. , Al-Khanferi N. M. , Al-Jaafari S. M.
Published: December 2007

A well in the Shaybah Field was recently worked over by converting the existing 1-km horizontal section to MRC (maximum reservoir contact) well with a total reservoir contact of 18,443 ft. The objectives of the workover program were to improve well productivity by maximizing the reservoir contact as well as to install solid expandable liner as a conduit for downhole flow control system in the future.

The original horizontal section was first extended by 6,462 ft, before running expandable liner. Installing a 1,008 ft 5–1/2" expandable liner in near horizontal section encountered considerable difficulties in this well, first with liner stuck, then experiencing stuck expansion cone during the final stage of liner expansion. After these problems were finally overcome, top of expanded liner was successfully pressure tested. Two laterals were sidetracked successfully out of the expandable liner (Lateral - 1 = 4,615 ft and Lateral - 2 = 7,366 ft) to access additional flow contribution from the reservoir.

This paper describes the experiences and lessons learned from hole preparation, running and expanding expandable liner, window exits of expandable liner, and subsequently drilling two 5–1/2" laterals.
Reservoir Evaluation Program Planning in HPHT Environments
Authors: Guillory C. M.
Published: December 2007

Reservoir evaluation is a significant challenge in the HPHT environment. With current technology, the ability to assess rock and fluid properties is very limited. Utilization of an assortment of MWD, wireline, geochemical, and gas logging technologies is necessary when attempting to fully assess reservoir properties. All of these evaluation tools have significant limitations and proper well and evaluation program design and planning is critical. Success is often dependent on making several measurements and having contingency plans developed in the planning stage of the evaluation program. Actual HPHT well evaluation planning and execution examples, as well as, current tool limitations and future technology requirements are reviewed.
Review of the Recent API PRAC Project Attempt to Evaluate the ISO DIS 10400 Failure Assessment Diagram Through Full Scale Testing of Pipe Containing Surface Imperfections
Authors: Moore P. W. , Prideco Grant , Maldonado J. G.
Published: December 2007

On going work by ISO TC67 SC5 Workgroup 2b to modernize the performance property equations of ISO 10400 / API 5C3 identified the need to begin research in an attempt to validate the Failure Assessment Diagram equations that incorporate variables of environment and retained surface imperfections in tubulars. A detailed research project proposal was drafted and submitted to the American Petroleum Institute (API) for consideration in their 2002 research budget. API approved and launched the research project which assembled the materials and conducted tests for two and a half years. Tubular manufacturers donated tubes, processing, inspection, and premium threaded end-caps, which greatly leveraged the API research funding. A consortium of Oil company operators, a metallurgical laboratory and tubular manufacturers donated post-fracture laboratory analysis of test samples that failed in an H2S environment in order to further enhance the understanding of the failure mechanisms. This paper identifies why the attempt to validate the environmental fracture equations for sour environments failed, one area where the project was successful, and enumerates the reasons why this type of research is recommended.
Improving Completion Viability in HPHT Completions
Authors: Carter T. S.
Published: December 2007

Environment – Assisted Cracking (EAC), also referred to as stress corrosion cracking, is a growing problem for oil and gas producers given the increased incidence of drilling in HPHT areas. It is a complex issue that is attributable to the interaction of sensitive, stainless steel metallurgy under applied or residual stress, with the various clear brine packer fluids used in today's critical completions. Applications of standard corrosion tests and experiments have generated very few of the answers needed to help producers predict how various combinations of tubular metallurgies and fluids will perform together in the well. Much more specific empirical data is needed to understand the mechanisms causing these failures, and how they can be avoided.

In an effort to find the difficult answers, two leading manufacturers of martensitic stainless steel tubulars, and clear brine fluids JFE and TETRA, have joined their technical resources to scientifically examine the phenomena of stress corrosion cracking. The technical alliance, which is called the ChemiMetallurgy™ research program, has developed an accelerated EAC test methodology that replicates known tubular failures that have occurred in the field over the past few years. Lessons learned have permitted extensive testing of multiple combinations of metallurgies and packer fluids to determine their interactions under actual well conditions.

By early in 2005, the testing protocol will have conducted more than 3000 tests gauging the interactions of more than 16 fluid combinations with 6 different chrome tubulars. These tests are being run under high stress, varying temperatures, with the additives, gases, and typical formation fluids that would be found in a well.

The testing to date has delivered some interesting surprises. Of special relevance is the importance of subtle differences in fluid and metal composition upon their susceptibility to EAC. Indications are clear: small differences can promote significant cracking consequences.

Results of these studies matching fluid with metallurgy not only minimize the risk of failure in the field, but also provide compelling economic benefits. Given a choice of several equidensity fluids that have been tested to be EAC compatible with specific tubulars, a fluid can be selected for use based on lower cost and/or other performance considerations.
Thermal Management of Closed Volume Spaces in Subsea Production Equipment
Authors: Beall Scott , McMillan Chris , Reinås Lorents
Published: December 2007

The design of Subsea production equipment for HPHT (15,000 psi / 350 °F) well applications require that HSE design consideration be given towards the management of closed volume spaces of incompressible fluids. A comprehensive thermal analysis of the tree system indicated that several areas could have the potential for pressure build up beyond the design rating of the equipment. For the area of greatest concern, a passive safety device was designed that provides overpressure protection in the event of an unplanned pressure build up.

This paper will discuss the methodology of the management of pressure build up in closed volume spaces due to thermal increases, with particular emphasis on the passive safety device used in the Christmas tree system for the Statoil operated Kristin field in the Norwegian North sea
Shell Exploration and Production Company List of Connections Tested for Well Service Pressures >8000 psi Based on Standardized API/ISO Qualification Testing Procedures
Authors: Valigura Gloria A. , Cernocky Paul
Published: December 2007

Shell Exploration and Production Company (SEPCo) has spent millions of dollars since 1980 to qualify connections for well service pressure greater than 8,000 psi internal differential pressure. Prior to 1998, API RP 5C5(1) was used to qualify connections. Since 1998, SEPCo has been qualifying connections consistent with ISO 13679:2002(2).

These connections have been qualified by testing, by product line qualification, or through extrapolation/interpolation from fully tested connections. In light of the potential for corrosion on metallic surfaces or handling damage, SEPCo requires that the connections for wells above 8,000 psi have two different types of sealing mechanisms: a metal seal and an independent resilient seal. Qualification and usage of tested connections with two proven seals has resulted in only four connection issues in wells (all attributed to incorrect rig make-up) over the last 20 years.

The actual connection test data are the property of the thread design company. For details of any of the test protocols and results, the appropriate thread design company should be contacted.
Rejuvenation of a Mature Oilfield Involving Polymer Flooding by Successful Tapping of Undrained/Unswept Oil: A Case Study
Authors: Yomdo S. , Talukdar B. N.
Published: December 2007

Zaloni Barail Second Sand (Well 27 Block) reservoir in Zaloni oilfield was discovered in 1957. For pressure maintenance, peripheral water injection was initiated by injecting water into the acquifer in 1973. Polymer flood project was undertaken in this reservoir in December 1975, which was a relatively new concept at that point of time, especially taking into account the depth of occurance (around 2650 metres) of hydrocarbon accumulation.

The current recovery from the reservoir is estimated to be around 42% of oil originally-in-place. In order to increase ultimate oil recovery, comprehemsive multi-disciplinary integrated studies were carried out in 2003 to re-define opportunities. Subsequently, an infill well drilled in this reservoir in July 2004 produced around 45 m3/day almost clean oil. Positive result obtained from the successful tapping of undrained / unswept oil in the reservoir, thus extending its producing life, has encouraged drilling of additional infill wells not only in this reservoir, but also in select undrained areas nearby.
Dykstra Parsons Water Flood Theory Adapted to Chemical Flood Modelling
Authors: Morrison G. R.
Published: December 2007

The method of Dykstra-Parsons, originally developed to model water flood performance, has been adapted to screen reservoirs for their Chemical / Polymer Flood suitability. Firstly, this paper summarises Dykstra-Parsons’ Theory alongside an automated method of tuning reservoir layer properties to [pre-chemical] water flood performance. (Methods of determining both layer permeability and oil-phase relative permeability end-points, from water-cut development, are presented.) Secondly, this paper describes the adaptation of Dykstra-Parsons’ Water Flood theory to model both chemical flood and post-chemical flood production performance. Permeability adjustment, mobility control, and alkaline-surfactant flood models are discussed.
Cross-SAGD (XSAGD)—An Accelerated Bitumen Recovery Alternative
Authors: Stalder J. L.
Published: December 2007

Steam Assisted Gravity Drainage (SAGD)1 has become the preferred in-situ recovery concept for Athabasca bitumen. However, to maintain steam-trap control, rates are limited by the close vertical spacing between the parallel horizontal wells. In Cross-SAGD (XSAGD) the injection wells are perpendicular to the producing wells. Sections of the wells near the crossing points are either restricted from the start, or are later plugged, to achieve a significant rate and thermal efficiency advantage over SAGD, especially in cases where low pressure is required.
Health, Safety and Environmental Risk Mitigation for a Thermal Oil Recovery pilot Facility in Trinidad
Authors: Khan F. , Sinanan B. , Jokhoo R. , Innis F. , Ramlogan V.
Published: December 2007

Enhanced Oil Recovery projects are strategic investment initiatives planned when oil prices are high enough to support economic profitability. The Upper Morne L'Enfer (UMLE) pilot thermal project, within the Forest Reserve oilfield in Trinidad, is the current thermal EOR activity. Within the last ten years, health, safety and environment laws and regulations have evolved and are now more stringently applied and practiced. The Forest Reserve field houses many sensitive forested environments. The surface operations include clearing and construction of a site for fluid storage, testing and the generator.

During the project-planning phase, an Environmental Impact Statement (EIA) and a Hazard Operability (HAZOP) Study were conducted to acquire Environmental Management Authority and Ministry of Energy and Energy Industry approvals and address potential safety and environmental risks associated with the project. Baseline data was extracted from an Environmental Impact Assessment that was recently conducted for drilling sixty wells in the same area.

Integrating the environmental baseline into the HAZOP study served to identify and rank both potential environmental and safety hazards, which in turn permitted Petrotrin to prioritize risk mitigation strategies. All parties involved in the risk assessments agreed that the team approach used in the HAZOP study permitted a more efficient and effective forum to identify and mitigate both safety and environmental risks as compared to combining results from individual assessments.

This paper describes how the project's potential safety and environmental risks were assessed and mitigated. The success in minimizing the risk associated with these hazards serves to demonstrate that oil and gas operations can coexist with sensitive environments.
Cyclic Mechanical and Fatigue Properties for OCTG Materials
Authors: Kaiser T. M. V. , Yung V. Y. B. , Bacon R. M.
Published: December 2007

Much of the design basis for well structures subjected to high amplitude cyclic loading is based on material assumptions that extrapolate strength properties from uniaxial, monotonic tests to conditions where cyclic, multiaxial stresses are imposed. This paper shows results from cyclic testing on common Oil Country Tubular Goods (OCTG) materials and demonstrates the difference between physical behavior measured under cyclic loading conditions and theoretical behavior extrapolated by numerical modeling of uniaxial, unidirectional test data. Modeling theories for plastic deformation are discussed, along with their limitations and relevance in a cyclic loading environment. The implications of these limitations for design choices in thermal wells also are discussed.

Fatigue properties for the high-amplitude, low cycle application of thermal operations have not previously been investigated in much depth, in particular for OCTG. Along with characterizing cyclic mechanical properties, the tests discussed here also were used to assess the low-cycle fatigue properties of steel commonly used for in thermal well casings. Consistent fatigue results were produced, which, applied in the context of analysis results using representative cyclic mechanical properties, provide a basis for estimating fatigue life for specific cyclic deformations. Depending on scenario assumptions, substantial statistical variation in fatigue life can be expected, so exact fatigue life predictions are not anticipated. The primary value in such modeling capability is the assessment of mitigation options for extending well life when casing deformations are indicated.

The paper also discusses some practical implications of the difference between actual material behavior and idealizations used for modeling purposes. An example application of the cyclic material behavior and fatigue life prediction is also included.
Investigation and Characterization of Fine Solids Isolated From a Froth Treatment Plant
Authors: Yang X. , Wang S. , Tran T.
Published: December 2007

Froth produced by hot-water extraction process usually contains about 60 wt% bitumen, 30 wt% water and 10 wt% solids. Water and solids are further removed in froth treatment process to obtain the acceptable bitumen product with minimal amount of hydrocarbon loss to tailing stream. Fine solids are known to play an important role in this three-phase separation, but little work has been done to characterize the fine solids and to investigate how their composition affects solids-bitumen interaction. In this work, several fine solids were isolated from the different streams in a froth treatment plant. The composition and properties of fine solids were characterized by Dean Stark Soxhlet extraction, PAS-FTIR, elemental analysis, and particle size distribution. It was found that composition and properties of the solids isolated from different sources are dramatically different. The solids that are more difficult to separate from hydrocarbon phase contained a significantly higher value of Fe element. Fe minerals in these solids were determined to be siderite. Besides siderite, kaolinite is another major component in the separated solids. The composition and particle size determine the interactions between solids and bitumen. The interaction between fine solids and bitumen adversely influences the bitumen/water/solids separation, affecting the quality of bitumen and resulting in hydrocarbon loss to tailings.
Analysis of a Macroscopic Nucleation Model for Simulation of the Solution-Gas Drive in Heavy Oils
Authors: Zaleski S. , Franco F. , Chraibi M. , Tardy P.
Published: December 2007

We present two versions of a Darcy-scale model for simulation of the solution gas drive in heavy oils.

Presence and behaviour of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made, in many institutions, in order to understand and model the solution gas-drive mechanism in primary heavy oil recovery. Conventional simulations succeed in matching actual field productions but are not reliable for prediction forecast purposes (large uncertainties on recovery factors). We present an evolving nucleation and flow model for solution gas drive in heavy oil.

The model is built at the Darcy scale and involves the effect of capillarity on bubble flow and phase change. An ad hoc simulation tool is built to analyze carefully the properties of the model. The tool allows to reproduce laboratory experiment across a sample rock. In the limit of infinitely slow depletion, an asymptotic theory is constructed that allows to predict analytically the pressure difference across a sample. The theory predicts a pressure gradient at first order without additional calculation, and the gradient appears, at first order, independent on the gas formation (degassing) kinetics. No saturation gradient is predicted at first order. The results are compared to numerical simulations and experiment, and good agreement is found in cases where the pressure gradient is known.

In a second version of our model we introduce the effect of capillarity on bubble growth. Capillarity delays bubble growth by stabilizing small bubbles under a certain critical radius. This new term leads to nucleation fronts propagating rapidly through the sample.

It appears more difficult to predict a saturation gradient. The causes of this difficulty are analyzed.
Study on Developing Low Permeability Reservoir With Waxy Oil By Cyclic Steam Stimulation
Authors: Yitang Z. , Bingyu J. , Xiuluan L. , Guangzhi L. , Dehuang S. , Yunting X. , Lianjie S.
Published: December 2007

An innovative way to improve the effect of developing low permeability reservoir with waxy oil by CSS is presented in this paper. The mechanism and feasibility of developing a specific waxy and low permeable reservoir by steam injection, Chaoyanggou reservoir in Daqing oil field, has been investigated. The results show that injecting high temperature steam into reservoir can not only reduce the viscosity of waxy oil, but also lead to the thermal expansion of the underground fluid and the distillation of the crude oil. The combining effect can improve sweep efficiency and enhance oil recovery efficiency. The effect of steam soak in two wells in Chaoyanggou oil field was first investigated by numerical simulation. Results demonstrated that using huff and puff method to develop waxy and low permeable reservoir is promising. After laboratory experiments and feasibility studies, a two-well field tests have been conducted in Chaoyanggou region using CSS technology. Encouraging results have been obtained from the field tests.
Understanding Reservoir Architectures and Steam Chamber Growth at Christina Lake, Alberta, by Using 4D Seismic and Crosswell Seismic Imaging
Authors: Zhang W. , Youn S. , Doan Q.
Published: December 2007

The Christina Lake Thermal Project, located 170 km South of Fort McMurray, Alberta, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the McMurray formation. The bitumen reservoir at Christina Lake is approximately 400m deep, and is delineated by over 300 vertical wells and extensive 3D seismic coverage. The McMurray formation can be informally subdivided into three units - Lower, Middle and Upper. The Middle unit contains the major bitumen bearing reservoir, while the Lower unit is generally water bearing and the Upper unit typically contains gas with some residual bitumen saturation. SAGD at Christina Lake was first implemented in 2001 (Phase 1, Figure 1). The currently developed project area is covered by time-lapse surface 3D seismic and crosswell seismic.

The 3D survey was acquired using mega-bin geometry, with a bin size of 12.5 m by 12.5 m. A baseline survey was conducted in 2001 followed by two repeat surveys in 2004 and 2005. In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in vertical wellbores. The goal of the survey is to better understand reservoir architecture by detecting lithology changes, including predicting the occurrence of mudstone stringers and their lateral and vertical distribution. Crosswell seismic data in this project have provided about one metre vertical resolution in the McMurray Formation, detected mudstone stringers, and indicated significant reservoir heterogeneity, all of which helped to more accurately characterize the reservoir and better predict reservoir performance under thermal operations. Results of the six profiles provide encouraging insight into the potential of crosswell seismic technology. Although there is a need for future research in several areas, crosswell seismic has the potential to complement and enhance the interpretation of surface 3D seismic.

Analysis of both 4D and crosswell data showed that steam chamber growth and oil recovery are strongly influenced by reservoir geology. Steam chamber growth is especially affected by the presence of low permeability facies in the vicinity of the SAGD well pairs. In each case to date, less than 100% of the well length contributes to oil production. These findings have significant impacts on the planning of future developments.
Status of Heavy-Oil Development in China
Authors: Shouliang Z. , Yitang Z. , Shuhong W. , Shangqi L. , Xiuluan L. , Songlin L.
Published: December 2007

China has significant heavy oil deposit of more than 1.9 billion tons of oil reserve in place (OOIP) with four major heavy oil producing areas, which are Liaohe Oil Field, Xinjiang Oil Field, Shengli Oil Field and Henan Oil Field. China has many types of heavy oil reservoirs such as single-layer, multi-layer, thick-blocked reservoir with wide range of oil viscosity from 100 cp to 100,000 cp and depth from 200m to more than 2000m.

Heavy oil has been produced for many years in China. However, the commercial heavy oil development was initial in 1982, when the first cyclic steam injection pilot test was successful in Liaohe Oil Field. In 1993, the heavy oil production had reached 10 × 106 tons per year. From then on, the annual heavy oil production has kept the level of 10~13 × 106 tons for more than 10 years.

The development manners of heavy oil reservoir are cyclic steam stimulation (CSS), steamflooding, waterflooding. CSS is the major manner, widely used in traditional-heavy, extra-heavy and super-heavy oil reservoir in China with the annual production more than 85% of total heavy oil production. CSS has become a mature industry technology, which includes high-efficient steam injection, artificial lifting, sand controlling, re-entry drilling, steam surveillance and so on. Steamflooding is successful in developing shallow heavy oil reservoir such as Karamy oil reservoir, including high-temperature profile conformance, surveying and steam measurement technologies.

This paper reviews the distribution of heavy oil resources, status of heavy oil development, trends and also the challenges faced in improving utilization of the resources in China.
Monitoring of Diffusion of Heavy Oils With Hydrocarbon Solvents in the Presence of Sand
Authors: Salama D. , Kantzas A.
Published: December 2007

Mass transfer of solvents in bulk heavy oil and bitumen was monitored successfully using X-ray Computer Assisted Tomography (CAT). Concentration gradients were obtained from analysis of bulk density maps as a function of location and time. Analysis of the data using Fick's Law provided apparent diffusion coefficients, which were consistent with previously published data using different solvents and different oils.

A second series of experiments was then performed whereby the heavy oil was mixed with sand at a level that is similar to what expected in heavy oil reservoirs. There was no connate water in the system. Different solvents were then placed on top of the oil/sand mixtures and the diffusion of the solvent into the sand pack was observed. X-ray CAT was used to monitor density and concentration profiles. Oil concentration profiles in solvent were clearly observed but the solvent concentration in the sand pack proved to be more challenging. The same Fickian approach that was used in bulk oil systems was applied to predict apparent diffusion coefficients for the liquid volume portion of the experiment. Preliminary results showed that the apparent diffusion coefficients are of the same order of magnitude as in the bulk oil systems.
Improved Steamflood Analytical Model
Authors: Chandra S. , Mamora D. D.
Published: December 2007

The Jones (1981) steamflood model incorporates oil displacement by steam as described by Myhill and Stegemeier, and a three-component capture factor based on empirical correlations. The main drawback of the model however is the unsatisfactory prediction of the oil production peak: usually significantly lower than the actual. Our study focuses on improving this aspect of the Jones model.

In our study, we simulated the production performance of a 5-spot steamflood pattern unit and compared the results against those based on the Jones model. Three reservoir types were simulated using 3-D Cartesian black oil models: Hamaca (9°API), San Ardo (12°API) and that based on the SPE fourth comparative solution project (14°API). In the first two field cases, a 45x23x8 model was used that represented 1/8 of a 10-acre 5-spot pattern unit, using typical rock and reservoir fluid properties. In the SPE project case, three models were used: 23×12×12 (2.5 ac), 31×16×12 (5 ac) and 45×23×8 (10 ac), representing 1/8 of a 5-spot pattern unit.

To obtain a satisfactory match between simulation and Jones analytical model results of the start and height of the production peak, the following refinements to the Jones model were necessary. First, the dimensionless steam zone size AcD was modified to account for decrease in oil viscosity during steamflood and its dependence on the steam injection rate. Second, the dimensionless volume of displaced oil produced VoD was modified from its square-root format to an exponential form.

The modified model gave very satisfactory results for production performance up to 20 years of simulated steamflood, compared to the original Jones model. Engineers will find the modified model an improved and useful tool for prediction of steamflood production performance.
Effects of Heavy-Oil/Solvent Interfacial Tension on Gravity Drainage in the Vapor Extraction (Vapex) Process
Authors: Yang C. , Gu Y.
Published: December 2007

The vapor extraction (VAPEX) process is a promising technology for recovering heavy oil and bitumen resources in an economically viable and environmentally friendly way. Although a number of laboratory experiments have been conducted to study the VAPEX process, the oil recovery mechanisms by gravity drainage in this process are not well understood yet. In this paper, both experimental and theoretical approaches are adopted to study the effects of gravity and the capillary force on gravity drainage in the VAPEX process. First, the interfacial tensions between a heavy oil sample and four different solvents (methane, ethane, propane, and carbon dioxide) are measured at different pressures below their respective vapor pressures by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Then, the Bond number, which is defined as the ratio of gravity to the capillary force, is calculated for the VAPEX process in a heavy oil reservoir and in a physical model of sand pack, respectively. It is found that the measured interfacial tension between the heavy oil and a solvent is reduced almost linearly with pressure for the four heavy oil-solvent systems tested. Correspondingly, the Bond number increases with pressure. An increased Bond number indicates relatively large effect of gravity on the VAPEX process and thus enhanced oil recovery.
New Completion Developments for the Production of Heavy and Extra-Heavy Oil in Eastern Venezuela
Authors: Brunings C. , Quijada W. , Grisoni J. C.
Published: December 2007

PDVSA San Tome along with a local manufacturer, have developed two different types of completion that have reduced cost and increase production while making the down hole completion operations simpler and faster.

Intelligent Completion. This type of completion was designed to be able to complete multiple production zones trough a single well bore, taking care of the need to monitor and control the production of each one of the zones individually as required by Venezuelan government.

For well MEL-226, the completion included two sleeves, one zone isolator and one tubing hanger, all of which were hydraulically set in a single trip, the packers were specially designed to allow passage of hydraulic fluid internally. This well was completed in sands zones R4 and T with electro submersible pump (ESP) and is producing 2,500 BPD of 11.5 API, which is 50% more production than conventional single zone completion in this area.

Hydraulic Set Steam Injection and Production Packer. The requirements for this "Injector/Producer" tool was needed to save on well intervention and rig time. The tool had to be set in highly deviated or horizontal sections. It had to allow the pumping of Nitrogen for casing insulation protection, and it required an integrated expansion joint to allow the thermal expansion of the pipe.

After using mechanical models, a 100% hydraulic packer called CB-TIET was designed and more than sixty units were installed, obtaining significant savings on rig time (20,000 $/well) and allowing five days of early production. Likewise, an Injector-Producer packer and steam injection ports were tried to improve the steam distribution throughout the horizontal section of a well located at the Bare Oilfield.
Impact of Operational Parameters and Reservoir Variables During the Startup Phase of a SAGD Process
Authors: Prada J. W. Vanegas , Cunha L. B. , Alhanati F. J. S.
Published: December 2007

This paper highlights how numerical simulation can be used as a tool to optimize the start-up phase of a SAGD process. During start-up, the main objective is to create a uniform communication path between the two wells by first circulating steam in both the injector and the producer well and then imposing a differential pressure between them. The dynamics of this process leads to important temperature and pressure transients that should be carefully considered when developing a start-up strategy. Usually, this start-up strategy aims at minimizing the time in which the well pair can be converted to full SAGD operation without causing any adverse effects on the long-term process performance.

A fully coupled wellbore/reservoir thermal simulator was used to conduct a sensitivity analysis, in which the effects of steam circulation rate, tubing diameter, tubing insulation and bottom hole pressure were investigated. The effects of the pressure differential between the wells, and the timing of imposing such pressure differential, were also looked at. To better account for the interaction between the processes happening in the wellbore and in the reservoir, the discretized wellbore was placed inside a hybrid reservoir grid. Aiming at investigating the influence of vertical and horizontal permeability, reservoir pressure, initial oil/water saturation and fluid properties, the start-up strategy was examined for three different cases representing the main heavy oil production areas in Alberta, Canada: Athabasca, Cold Lake and Peace River.
Temperature Distribution in Natural Gas/Condensate Pipelines Using a Hydrodynamic Model
Authors: Sadegh A. A. , Adewumi M. A.
Published: December 2007

A hydrodynamic model for predicting the flow of natural gas and condensate in transmission pipelines has been developed. This steady state model was used to study the temperature profile along a transmission pipeline. The model is based on formulating the problem in terms of mass, momentum, and energy balance equations. Thermodynamic properties are determined using flash and thermo-physical properties calculators based on a Volume Translated Peng-Robenson EOS (VTPREOS).

This new model will provide gas transmission engineers with a versatile tool for modeling multiphase flow in pipelines. It will also provide approximations to the parameters of most importance to them specifically, the impact of temperature and terrain effects on liquid dropout. Liquid formation is a major concern for transmission companies due to the significant decrease in gas flow capacity, inaccuracy in metering, and potential damage to instrumentation and equipment. This model simply tells the field engineer where and how much liquid will form. This information is valuable for locating and sizing liquid collection tanks, and in the design of a cost effective pigging schedule.

The results of the systematic numerical studies showed that the temperature of the gas decreased from the inlet condition to that of the surrounding temperature within 3 miles of the inlet. In addition a temperature rise of up to 5 degrees Fahrenheit was observed when an undulating terrain was simulated (in downhill flow).
Recent Advances in Aphron Drilling Fluids
Authors: Growcock F. B. , Belkin A. , Fosdick M. , Irving M. , O'Connor B. , Brookey T.
Published: December 2007

Aphron drilling fluids are being used globally to drill through depleted reservoirs and other under-pressured zones. The primary features of these fluids are their unique low-shear rheology and aphrons (specially designed pressure-resistant microbubbles of air). However, how aphron drilling fluids work is not well understood, which limits acceptance of this technology, along with efforts to optimize the system's performance. Recently a study was undertaken under the auspices of the U.S. Department of Energy to gain some understanding of the workings of aphron drilling fluids. Those results are presented here.

Various laboratory techniques were applied to determine the physicochemical properties of aphrons and other components in the fluid and how they affect flow through permeable and fractured media. These included wettability and surface tension, bubble stability, radial and dynamic flow visualization, and fluid displacement tests.

One key discovery was that aphrons can survive compression to at least 4000 psig, whereas conventional bubbles do not survive long past a few hundred psig. When drilling fluid migrates into a loss zone under the drill bit, aphrons move faster than the surrounding liquid phase and quickly form a layer of bubbles at the fluid front. At the same time, the shear rate of the fluid continually decreases and the viscosity is rapidly rising. The combination of the bubble layer and the rapidly increasing viscosity of the liquid severely curtails fluid invasion. Another key finding of the study is that aphrons show little affinity for each other or for the mineral surfaces of the pore or fracture; consequently, the seal they form is soft and their lack of adhesion enables them to be flushed out easily during production.

Depleted wells which are very expensive to drill underbalanced or with other remediation techniques can now be drilled overbalanced. This study has provided a sound technical basis for the success of aphron drilling fluids and is providing guidance on the way to run these fluids in the field to optimize their performance.
Determination of Effective Drainage Area for Tight Gas Wells
Authors: Cox S. A. , Sutton R. P. , Stoltz R. P. , Knobloch T.
Published: December 2007

Early quantification of the well's ability to effectively drain the productive reservoir will result in improved economic performance. The effective drainage area of a tight gas well is primarily controlled by reservoir geometry, rock and fluid properties and well completion efficiency. This paper will present theoretical effective drainage areas for wells completed in blanket sands (radial drainage) and channel sands (linear drainage). The work will focus on the relationship between reservoir geometry, effective gas permeability, porosity and fracture half-length for dry-gas reservoirs.

The relationship of effective gas permeability and fracture half-lengths on the effective drainage area will be presented as a result of this work. Typical Appalachian Basin producing reservoir properties will be incorporated into the simulation work tailoring this analysis to those producing environments. The cases presented in this paper will include permeability ranging from 0.01 md to 1 md, reservoir geometries ranging from radial flow to channel widths from 250 ft to 1000 ft and fracture stimulation half-lengths up to 300 ft. For consistency, all stimulation cases will be based on an assumed 200 md-ft fracture conductivity.
Screening and Evaluation of Some Environment-Friendly Mud Additives To Use in Water-Based Drilling Muds
Authors: Amanullah M.
Published: December 2007

Environmental safeguard policies enacted by EPA, state and federal governments for effective management of onshore, offshore, coastal and other areas dictate the identification of environment friendly muds and mud additives. The increasing concerns of world communities to protect the global environment from the detrimental effect of oil-based muds dictate the use of environment friendly water-based muds. However, water-based muds with excellent environmental characteristics often become obsolete due to poor technical performance and low thermal stability. This paper describes the results of three novel mud additives to control the viscous, fluid loss and thermal stability of water-based muds.

A comparative study of the viscosity generating characteristics of a newly identified viscosifier indicates better performance at the same concentration with respect to a widely used viscosifier. Several fluid loss additives, developed using an environment friendly technique, show better performance than a widely used fluid loss additive. A newly identified thermal degradation inhibitor improved the thermal stability of a bentonite mud up to 150 °C.

Experimental data indicate more than 100% increase in PV, 400% increase in YP and 200% increase in 10 seconds gel strength for the base bentonite mud after hot rolling at 150 °C for 16 hours. However, this mud showed about 40% increase in PV and virtually no change in the YP and thixotropic property after hot rolling at 150 °C for 16 hours in the presence of the newly identified thermal degradation inhibitor.