bluuebunny/crossref_metadata_2025 huggingface dataset:
A New EOR Application in a Gas-Oil System
Authors: Stevenson M. D. , Skinner R. C. , Clifford P. J.
Published: December 2007

Gravity drainage in a gas-oil system can be an efficient natural recovery process and may give rise to high unit recovery efficiencies. However, as the Gas-Oil Contact descends during drainage, there is a large, effectively immobile, oil target remaining.

Detailed mechanistic studies have been performed where a miscible injectant (MI) hydrocarbon gas has been injected into the expanded gas region to recover additional oil and to accelerate production compared with continued gravity drainage. The studies were performed with finely gridded fully compositional models in both 2 & 3 dimensions. This work has built upon the significant EOR experience of three phase water-dominated systems and begins to explore two phase gas-dominated EOR processes.

There are a number unique features of the two-phase Gravity Drainage Miscible Injection (GDMI) EOR process including: –The importance of vapourisation for "oil" transport;–A condensation imbibition mechanism;–The MI having greater density than the carrier fluid;–Utilisation of gravity and reservoir flux as drive for the MI;–Some dilution of MI by mobile free gas;–Low MI trapping.

The results of the study indicate that GDMI is a viable recovery process that can be used to selectively target immobile oil at high gas saturations and, under certain conditions, achieve recovery efficiencies comparable to conventional EOR processes such as Water Alternating Gas (WAG).
Hydraulic Fracturing for Sand Control in Unconsolidated Heavy-Oil Reservoirs
Authors: Wedman Mark L. , Lynch Keith W. , Spearman Jim W.
Published: December 2007

The North Slope of Alaska has significant accumulations of low API-gravity oil in unconsolidated formations. The combination of low-productivity wells in relatively unconsolidated formations in the arctic environment presents many challenges. Consequently, both formation stimulation (for economic production rates), and sand control (for acceptable operating costs) are required. A fracturing technique for sand control (FSC) with a resin-coated proppant (RCP) for proppant-flowback control proved feasible in laboratory testing. The initial attempts at field implementation were an investment in learning that resulted in a large number of first-order failures resulting from proppant and formation flowback. With these early failures, these attempts were not commercially viable. Laboratory investigations and field tests revealed the source of the problems, and led to design changes and improvements in implementation procedures. Field results have demonstrated that the FSC completion is a viable technique within certain formations on the North Slope that can achieve the stated goals of effective stimulation, proppant-flowback control, and sand control.
Testing While Underbalanced Drilling: Horizontal Well Permeability Profiles
Authors: van Kruijsdijk Cor P. J. W. , Cox Richard J. W.
Published: December 2007

Underbalanced drilling has gained popularity during the last years as it is well-suited to the drilling of low-pressured reservoirs and provides a method to prevent formation damage, especially in horizontal wells. The production rate of formation fluids during drilling carries information on reservoir characteristics. In particular, the permeability profile along the well may be inferred from a combination of well pressure and total rate.

The transient well inflow can be interpreted as a complex well test. The complexity arises from the fact that the boundary conditions (i.e. the well trajectory open to flow) change with time during the test. Moreover, the transient rate is influenced by variation in underbalance (i.e. well pressure) and well penetration rate. However, the signal (transient rate) carries detailed information on the permeability profile along the well. Analysis is preceded by the elimination of the effects of the variable underbalance and drill speed using deconvolution techniques. An accurate approximation of the permeability profile can be obtained by a direct analysis (i.e. without having to resort to history matching) of the corrected well influx. Note that only the total well rate trqnsient is required rather than the full inflow profile along the open well trajectory.

In previous work we considered the analysis of the transient rate during underballanced drilling of a vertical well under a constant underbalance. Both the variable underbalance and the more complex outer boundary conditions of a horizontal well (the transient is very likely to see the cap-and base-rock boundaries during the test) distinguish the current study from the previous one.
Boosting Horizontal Well Performance In Carbonates By Selective Stimulation: Field Cases From Qatar
Authors: Sannier Yann , de Lapasse Hubert , Kirkhus Rune , Richard Claude
Published: December 2007

To enhance oil productivity in its Alkhalij field offshore Qatar in 1997, Elf Petroleum Qatar took the decision to complete the carbonated Mishrif reservoir through horizontal cemented perforated liners. The vertical or subvertical wells in this field produced an average of 3000bbl/day per well. The last 5 horizontal wells were put on stream at a more than of 8000bbl /day flow rate.

To achieve maximum productivity from the horizontal drains, complete entry exposure had to be established along the entire length of the horizontal section. To meet this objective the perforated sections of the drain were stimulated in two stages as follows: by opening the perforations in the toe of the horizontal section by pumping acid through coiled tubing and thenby performing the main acid job by bull heading, through the DST string, a retarded triphase acid system (emulsified acid diesel solution with nitrogen) with ball sealers as the diverting agent.

This paper documents the engineering methodology and the operational techniques employed on 5 horizontal wells to selective stimulate producing intervals of between 600m. and 1,200m. length.

Case histories are presented to illustrate procedures, treatment designs and productivity results.
A New Method for Determination of Reservoir Pressure
Authors: Kuchuk Fikri J.
Published: December 2007

This paper presents a simple and practical technique for determination of reservoir pressure from pressure buildup tests. The technique is based on the wellbore pressure solutions to an instantaneous source, including wellbore storage (afterflow) effects. The new technique is applicable to different flow regimes, such as cylindrically and spherically radial. The technique is sufficiently general that it may be applied to a wide variety of well/test configurations such as DST and wireline formation tester as well as vertical and horizontal wells.

The new technique is compared with the well-known Horner method. If the flow rate is well stabilized and the producing time is sufficiently long before the buildup test, the technique gives the same results as the Horner method. However, the new technique works better than the Horner method if the producing time is short, the flow rate is unstable and/or flow regimes are not fully developed.

Well tests in low-permeability (tight) or low-pressure reservoirs are well suited for this new technique because frequently they do not flow to the surface or sustain the flow rate long enough so that the conventional interpretation methods can be used. The technique can also be applied readily to wells in unconsolidated formations that produce sand, which usually plugs the wellbore during flow periods. For these cases, the technique will provide good estimates for permeability, skin, and reservoir pressure. A few buildup test examples are presented for the application of the technique.
High-Speed Downhole Memory Recorder and Software Used to Design and Confirm Perforating/Propellant Behavior and Formation Fracturing
Authors: Schatz J. F. , Haney B. L. , Ager S. A.
Published: December 2007

Propellants, now sometimes combined with perforating guns, have the potential to clean up damaged perfs, penetrate near-wellbore damage, and create formation fracturing. Although some of these dynamic techniques have been available for years, the lack of a standard measurement and analysis method has restricted their widespread use. Now, improved ultra high-speed downhole memory data recorders and computer software fully incorporating well, perforation, and tool details address this issue. Hardware and software are described. Several demonstration cases show the use of this technology in the field for vertical and deviated cased and open hole wells. Dynamic pressure data are compared with calculations and the realism of the results is shown, as well as how to make procedural and design improvements. The combination of the new recorder and software for the design and evaluation of dynamic well treatments allows the optimization of job design, and the evaluation of post-job results to understand tool performance and improve future tools and applications.
An Analysis Technique for Optimising Reliability in System Design
Authors: Hother John A
Published: December 2007

This paper describes an analysis technique, developed for improving systems reliability in the aerospace and defence industry, that can be used in the oil & gas industry for engineering projects demanding high reliability, such as subsea production systems and deepwater remotely operated vehicles (ROVs).

The method, called Reversionary Mode Analysis, is based on the same principles as the well-known Failure Modes Effects & Criticality Analysis (FMECA). It is used to determine the effects, on the operational performance of the system, of failures in the constituent parts and thence to optimise the system's resilience to failures. Its output is similar to that of FMECA in essence, but it does not depend on statistical data, and so can be used in circumstances where FMECA is not appropriate in its traditional form, such as when quantitative, statistical input data is not available.

Reversionary Mode Analysis has delivered important benefits in, for example, air defence systems - Highlighting areas of the system design that need priority attention to improve fault-tolerance;Confirming that design changes really do improve the fault-tolerance;Reassuring the customer that the proposed system will deliver the desired degree of fault-tolerance.

The paper explains how the technique was developed to meet customer demand for demonstrable fault tolerance in new systems at the design stage. The technique is then described in the form of six steps. The issues of who is best equipped to use the method, and when is the best time to apply it, are explored. Finally, the paper recommends how the technique can be applied to oil & gas projects, to deliver the benefits.
Field Investigation of the Effects of Stick-Slip, Lateral, and Whirl Vibrations on Roller Cone Bit Performance
Authors: Chen S. L. , Blackwood K. , Lamine E.
Published: December 2007

The effects of downhole vibrations on polycrystalline diamond compact (PDC) bit performance have been well discussed in recent years. However, most research on the downhole dynamics of roller cone bits has focused on axial vibration and its effects on bit performance. The questions which remain to be answered are: What kind of vibrations does a roller cone bit experience, and what are the effects of these vibrations on roller cone bit performance?

To investigate these questions, a series of field tests was conducted in a full scale drilling research rig, with downhole vibration data recorded by an advanced instrumented sub. Soft to medium hard formations were drilled using four 8½-in. roller cone bits (IADC Code 517. Three kinds of harmful vibrations were observed, and their effects on bit performance in terms of rate of penetration (ROP), insert breakage, and bearing/seal and bit life are discussed.
Rock Strength Measurements on Cuttings as Input Data for Optimizing Drill Bit Selection
Authors: Uboldi V. , Civolani L. , Zausa F.
Published: December 2007

Selecting the most appropriate bit for any hole section is a key-feature in achieving superior drilling performance. The aim, to maximize hours on bottom and rate of penetration without jeopardizing safety and bit integrity, in order to improve and optimize performance. These factors have an enormous influence on the drilling and ultimately well economics.

The most important factor to correctly select, or even design "ex novo", a bit, is to understand how the bit cutting structure effects the rocks to be drilled. These interactions depend on formation physical characteristics, mainly rock structure and nature, compressive strength, abrasiveness, wettability, under-overbalance etc. The conventional approach in bit selection is to derive actual expected performances on reference data such as previous runs or information from offset bit records. In this way, the achievement of improved performances and optimization may require a long time and much expense.

Analyzing the formation characteristics while drilling directly on cuttings, we may obtain substantial information that lead to define the most suitable cutting structure for any specific hole section, leading to identification of the most suitable bit and saving valuable time and money.

In order to reach this goal, a methodology has been developed, based on micro indentation tests on cuttings, to mechanically characterize formations. The compressive strength index values obtained by micro-indentation are then used by a Drill Bit Optimization System to aid Operators with the bit selection decision.

This system uses lithological data and compressive strength values as input and provides bit class indication, together with bit hydraulic configurations and gage protection as output.

After an introduction devoted to illustrate the indentation tests, focus will be given to the actual results of field tests. We will detail the methodology and the verification process as performed during the field tests, carried out in a very demanding environment in central-southern Italy, and will point out how it can be easily implemented at the rig site, practically at no extra cost.

Furthermore, discussion will cover how the planning of new drilling activities may benefit from the results derived by the Drill Bit Optimization System, supplied with data from the micro indentation test eventually validated by E-logs, in order to maximize penetration rate and drilling efficiency.
Dielectric-Independent 2-MHz Propagation Resistivities
Authors: Wu Peter T. , Lovell John R. , Clark Brian , Bonner Stephen D. , Tabanou Jacques R.
Published: December 2007

All commercial 2-MHz and 400-kHz propagation resistivity logging-while-drilling (LWD) tools use an assumed value or relationship for dielectric permittivity to derive independent resistivities from phase shift and attenuation measurements. This methodology has been used for over ten years. For resistivities below 100 Ω-m, the phase shift resistivity is not strongly affected by the assumed value of dielectric constant. In contrast, the attenuation resistivity is sensitive to the assumed dielectric constant above 10 Ω-m, and extremely sensitive above 50 Ω-m. A new empirical relationship between relative dielectric constant and resistivity is proposed to improve the phase shift and attenuation resistivities above 100 Ω-m. However, in high resistivity formations, and in unusual lithologies with exceptionally large dielectric permittivities, it is better to invert the measured phase shifts and attenuations together to obtain an apparent resistivity that is independent of the dielectric constant. This "dielectric-independent" resistivity will be free of possible errors caused by assuming a wrong value for dielectric permittivity. Even though phase shift and attenuation resistivities exhibit different vertical and radial response characteristics, simulations show that bed boundaries and moderate invasion do not adversely affect the computation of the dielectric-independent resistivity. In oil based mud, it is possible to read resistivities above 1000 Ω-m. This provides the ability to differentiate among high resistivity formations, but not necessarily the ability to measure a quantitative value. Three field examples illustrate the strengths and limitations of the dielectric-independent resistivity.
How to Measure Exploration-Production Efficiency
Authors: Komlosi Zs.
Published: December 2007

A complete proper economic analysis of a known property yields different investment indices. The bests of them must satisfy the 3H rule, i.e., they must answer all three questions: How much return may be expected? How much capital is required? How long does the E&P process last? Several yardsticks had been analyzed. There was established that Growth Rate of Return ("GRR") and Internal Rate of Return ("IRR") are the only yardsticks fulfilling the 3H rule completely. Comparison of the investment rank of properties is suggested by GRR. Application of Monte Carlo simulation allows estimating, besides the most probable value, the quantity of risk taken with property.

In case of an unknown property (i.e., exploration) the stochastic evaluation using Monte Carlo simulation gives the most sophisticated solution calculating probability distribution of any yardsticks. During the evaluation, probability distributions of the unrisked input parameters (such as e.g., reserve, production forecast, future expenses and prices) of cash flow model of complete E&P process are to be estimated. When limited information or time available input parameter-values for a few outcomes (e.g., high, low and most probable) and relevant probabilities are required. Then, Monte Carlo simulation of cash flow model with input parameters yields probability distribution of results (e.g., net present value and expected return/risk). Ranking or comparison properties done by expected values, first.

The economic value and the risk associated with a company's exploration portfolio can be calculated with Monte Carlo simulation from probability distributions of the net present values that derived from each property to be explored. The expected value of the portfolio can be compared to the property's values of "normal" risk, such as reserve acquisition and production. Judging a new exploration venture requires analysis of how the new property it affects on the value and the risk of company's exploration portfolio.
Overcoming Slugging Problems in a Long-Distance Multiphase Crude Pipeline
Authors: Al-Kandari Ali Hussain , Koleshwar Vilas S.
Published: December 2007

The paper discusses the wide range of issues arising out of the slugging problems experienced in a 36 km. long, 36" multiphase pipeline gathering well fluids from several ESP fitted oil wells of a distant oil field in Kuwait and processing it in a gathering center. Over a time frame of 3 to 4 years, the slug characteristics of this line showed substantial increase on account of gradual increase in flow, GOR and water cuts of the flowing well fluids.

The higher liquid content slugs at the current production level began to give severe operational difficulties in the separators at the gathering center. These slugs further resulted into HSE related issues like severe pipeline vibrations, weakening of pipe supports, corrosion and excessive smoke flaring.

The paper will discuss some of the quick fix actions taken to eliminate the above mentioned slugging problems and bring back the operations to normal. Such quick fix actions were taken without shutting down the facility and without any major modifications. As is sometimes the case, operational compulsions demand the ability to utilize what is available to ensure that production losses are minimized.

The paper also provides the back-up calculations to show how the flow regime changed to undesired condition over a period and how the same was favorably changed to a more manageable flow regime.

Based on the lessons learnt from the above-mentioned case, the paper identifies and recommends variety of techniques to enable operations to maximize efficiency of their multiphase flowlines.
Experimental Study of Low Liquid Loading Gas-Liquid Flow in Near-Horizontal Pipes
Authors: Meng Weihong , Chen Xuanzheng T. , Kouba Gene E. , Sarica Cem , Brill James P.
Published: December 2007

Low liquid loading flow in wet gas pipelines is a common occurrence in the transport of unprocessed raw gas. The most important parameters governing the flow behavior are pipe geometry (inclination angle and diameter), operating conditions (flow rate, pressure, and temperature), and physical properties of the gas and liquid (density, viscosity, and surface tension). In this study, extensive experiments were conducted using a test loop made of 50.1-mm diameter acrylic pipe with inclination angles from the horizontal of -2°, −1°, 0°, 1°, and 2°. Gas and liquid superficial velocities ranged from 5 to 25 m/s and from 0.001 to 0.053 m/s, respectively. In-situ liquid loading ranged from 150 to 1800 m3/MMm3. Flow patterns studied were stratified (smooth and wavy) and annular. Measured parameters included gas and liquid volumetric flow rates, liquid film flow rate, pressure drop, temperature, liquid holdup and droplet deposition rate.

The experimental results show that, at low liquid loading, there is a broad transition range from stratified wavy flow to intermittent flow. Entrainment can occur in the gas core at relatively low gas velocities, and droplet deposition occurs simultaneously with entrainment. An increase in gas velocity did not increase liquid entrainment fraction over a relatively broad range of gas velocities. However, an increase in liquid flow rate did increase the liquid entrainment fraction. Surprisingly, in the annular flow region, a new phenomenon was observed at certain superficial gas velocities: an increase in liquid flow rate decreased the liquid film flow rate and liquid holdup, and increased the entrainment flow rate. This phenomenon may have significant impact on operations to sweep liquids from wet gas pipelines. Seven correlations of liquid entrainment onset point and entrainment fraction in the gas core are evaluated and modified to better fit the data. A new interfacial friction factor closure relationship is proposed. Based on this new information, a procedure is proposed for calculating low liquid loading in wet gas pipelines. The data obtained, the interfacial correlation developed and the proposed procedure to estimate liquid loading can be used in designing wet gas pipelines, determining pigging frequency, and predicting hydrate formation in deep water wet gas pipelines.
A Review of Field Performance of New Propellant/Perforating Technologies
Authors: Gilliat Jim , Snider Phillip M. , Haney Robert
Published: December 2007

The use of propellants as a production enhancement tool is not new in the petroleum industry. However, the concept of combining the propellant into a sleeve form with the perforating gun is unique. This technology has recently been introduced to the oilfield and shows promise of solving many of the inherent preforating problems for which solutions have been needed.

This paper will review the development of the combined propellant and perforating technique and will use case histories that focus upon tubing-conveyed applications to document the positive effects gained by combining these technologies. The case histories will present some of the operational successes as well as some of the failures experienced to date.

The propellent/perforating technique has been applied in both extreme over- as well as underbalanced well conditions in approximately 1,000 wells. It has proven that it can offer a cost-effective, safe method when used as a near wellbore clean up tool and for prefrac preparation. Additionally, its usage can eliminate other service needs that often occur subsequent to perforating. These facts will be evidenced by the case history experiences disclosed in this paper.
Foam for Gas Mobility Control in the Snorre Field: The FAWAG Project
Authors: Blaker T. , Celius H. K. , Lie T. , Martinsen H. A. , Rasmussen L. , Vassenden F.
Published: December 2007

The FAWAG Project (Foam Assisted WAG) is a full-scale demonstration by Saga Petroleum of the use of foam for gas mobility control. The injection of foam started in the Central Fault Block at the Snorre Field in August 1998, after a two-year planning period and many years of active research. The first phase of the project, Surfactant-Alternating-Gas (SAG) injection was completed late 1998, and the co-injection phase is expected to be completed by Summer 1999. Approximately 2000 tons of commercial grade surfactant will be injected in the project. The project is partly sponsored by the European Commission's Thermie program.

The paper presents the basic concept behind the method, the selection of chemicals, the logistics for handling of the chemicals and the technical modifications needed on the offshore facility to perform the injection. Preliminary results, particularly the response from the injector, is presented for the first phase of the project.
Environmental Impact Assessment for the Salalah Gas Pipeline
Authors: Simons David J. , Adams Marcus B.
Published: December 2007

The planned route of the proposed Salalah Gas Pipeline will traverse 700 kilometres of desert and ecologically sensitive mountainous terrain from the centre of the Sultanate of Oman to the southern coast at Salalah. Petroleum Development Oman LLC (PDO) has commissioned extensive environmental studies during the definition phase of the pipeline design resulting in an Environmental Impact Assessment (EIA), and in the production of Environmental Management and Construction Specifications. Detailed analysis of the environmental baseline, together with in-depth sociological studies and a commercial crop inventory, have allowed a highly project-specific EIA to develop. Extensive and innovative mitigation measures have been identified to alleviate the impact of routing the pipeline through the unique and internationally recognised ecosystem of Jebel Qara and through the sociologically sensitive Salalah Plain. PDO's internal environmental engineering guidelines have been updated to reflect a growing awareness of the advantages of such prescient environmental studies. This paper describes the joint Company and Consultant approach to the studies, the findings, and the recommendations for impact mitigation in a unique and fragile environment.
The Answer to Increasing Environmental Compliance Costs: Regulatory Reform or Technological Advance?
Authors: Godec Michael L. , Petrusak Robin L.
Published: December 2007

Environmental compliance requirements on the U.S. E&P (E&P) industry continue to rapidly evolve and become more stringent. Controlling the costs of environmental compliance, without sacrificing industry's and governments' commitment to environmental quality, will continue to be a priority, especially in a world of sustained low prices.

This paper examines a number of potential legislative and regulatory initiatives that could affect environmental requirements on the U.S. oil and gas E&P industry. The paper provides a quantitative assessment of these initiatives on oil and gas supplies, government revenues, and industry activity (e.g. drilling, E&P expenditures, etc.). The paper also examines some of the major emerging technological developments that could reduce the E&P industry's future expenditures for environmental compliance. These technological developments include the use of synthetic drilling fluids in offshore operations, evolving technology for downhole separation of produced water and oil, and improved technology and industry practices to reduce emissions of toxic air pollutants and potential greenhouse gases. The paper will compare and contrast the potential benefits associated with the two alternative approaches to reducing compliance costs – regulatory relief and technological advance – and provides some thoughts on the relative benefits and potential liabilities associated with each approach.

This study concludes that for the period 2000 to 2010, a stringent regulatory compliance scenario could result in $11.7 billion more expenditures by industry for environmental compliance, relative to a less stringent, risk-based regulation scenario. Potential compliance requirements related to drilling and drilling waste management are estimated to account for about one third of the potential environmental compliance expenditures, and potential requirements related to stringent regulation of hydraulic fracturing are estimated to account for almost half the potential compliance expenditures. In contrast, aggressive development and implementation of environmental compliance technology results in approximately $1.8 billion in savings in overall industry expenditures for environmental compliance during the same period. An estimated 90 percent of this potential savings is associated with downhole water separation. In the regulatory case comparison, where the risk-based case is considered the baseline, the more stringent regulatory scenario results in a 38 million barrels per year drop in oil production by 2010. Similarly, the more stringent regulatory scenario results in a 90 Bcf per year drop in gas production by 2010. In the technology case comparison, where the risk-based regulation case is considered the baseline, the aggressive environmental technology case results in a 37 million barrels per year increase in oil production by 2010. Similarly, the environmental technology scenario results in a 40 Bcf per year increase in gas production by 2010.
A Case-Based System to Cut Drilling Costs
Authors: Irrgang R , Damski C , Kravis S , Maidla E , Millheim Keith
Published: December 2007

The best wells in a basin may be drilled twice as quickly as the worst. New technologies such as slimhole and extended reach drilling are not easily mastered. What factors determined the success of the best wells? What caused the delays? Data management processes and computational tools for planning new wells have been developed to utilise past experiences recorded in drilling data and reports. The Case Based Reasoning technique is applied to derive new scenarios (alternate drilling plans) based on previous "cases". A number of oil companies are collaborating to form a "Drilling Club" and have contributed well data and drilling reports from around the world. An immense amount of data and experience is available from many wells but engineers would prefer to see just the relevant information. The system assists by extracting an intelligent summary and structuring information to highlight key factors that will result in the greatest cost savings on a proposed drilling operation. Scenarios using alternative technologies can also be tested with risks calculated based on previous similar cases.
Slug Tracking in Hilly Terrain Pipelines
Authors: Yehuda Taitel , Barnea Dvora
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
A Mechanistic Model for Gas-Liquid Flow in Pipes with Radial Influx or Outflux
Authors: Ouyang Liang-Biao , Aziz Khalid
Published: December 2007

A new mechanistic model for gas-liquid two-phase flow with mass transfer through the pipe wall, which accounts for the effects of wall inflow or outflow on wall friction, acceleration and flow pattern transition, has been developed. Four individual flow patterns, including stratified flow, annular-mist flow, bubble flow and intermittent flow, are considered in the mechanistic model. Models for individual flow patterns have been developed. Transition mechanisms among different flow patterns are discussed and new transition criteria are proposed.

Predictions by the new mechanistic model are compared with experimental data obtained on a large industrial facility.
High Temperature Blow-Down Experiments in a Vuggy Carbonate Core
Authors: Dehghani Kaveh , Kamath Jairam
Published: December 2007

Steam injection followed by pressure reduction (high temperature "blow-down") has been recently proposed to improve recovery from a light oil vuggy carbonate reservoir.1 We conducted experiments on a core sample from this reservoir in order to quantify the recovery mechanisms. These comprise thermal expansion, thermally enhanced solution gas drive, dry distillation, and in-situ steam drive.

We used Computed Tomography (CT) imaging of a miscible flood to characterize the connectivity of the vugs and matrix rock. We then conducted a series of blow-down tests. Here we heated the core to 300 degF and used a backpressure regulator set just above the bubble point of the oil at 300 degF. The pore pressure was then reduced at a constant rate from one end of the core sample. The first blow-down test was with the core at initial oil saturation with pressure reduction from the top of the sample; the second at initial oil saturation with pressure reduction from the bottom; and the third at residual oil saturation to water with pressure reduction from the top. The volumes and compositions of the produced fluids were measured in all the blow-down tests. We also CT imaged the initial and final oil saturation distribution for the second blow-down experiment.

The CT images reveal that the core sample contains vugs, high permeability matrix, and low permeability matrix rock; and that the vugs are connected through the high permeability matrix. The blow-down experiments show that 50-68% of the oil is recovered; with 8-20% due to thermal expansion, 20-24% due to thermally enhanced solution gas drive, 12-16% due to dry distillation, and 8-10% due to in-situ steam drive.
An Investigation of the Steam-Assisted Gravity-Drainage Process in the Presence of a Water Leg
Authors: Doan L. T. , Baird H. , Doan Q. T. , Farouq Ali S. M.
Published: December 2007

Many heavy oil and oil sand reservoirs are in communication with water sand(s). Depending on the density (°API gravity) of oil, the water sand could lie above or below the oil zone. Steamflooding a heavy oil or oil sand reservoir with a contiguous water sand (water which may lie below or above the oil-bearing zone) is risky due to the possibility of short circuiting the steam chamber.

The Steam Assisted Gravity Drainage (SAGD) process was first tested at the Underground Test Facility (UTF) in Fort McMurray, Alberta. The successful application of this process to Athabasca-type oil sands has extended its application to other heavy oil and oil sands reservoirs. To date, the application of this process to a variety of different reservoirs has shown mixed results due to a variety of reasons. In our opnion, the success of these projects depends on: 1) accurate reservoir description, 2) efficient utilization of heat injected into the reservoir, 3) understanding displacement mechanism, 4) understanding of geomechanics (the interaction between the fluids and the reservoir at elevated temperatures and pressure), and 5) overcoming various operational constraints. This paper looks at how the SAGD process is affected by the presence of water sand, and determines how heat is distributed in these reservoirs.

Results of this numerical simulation study show a relationship between ultimate recovery, heat accumulated in the reservoir and the thickness of the water sand (bottom or top water). For the base case run, an average rate of 80 m3/d was maintained for 1400 days before it started to decline. Ultimate recovery was approximately 70% of the OOIP after 9 years of steam injection, and the cumulative OSR was 0.3 m3/m3 (CWE). The presence of a bottom water sand has a lesser impact on recovery than the case where an overlying water sand is present. As the thickness of the water sand increases, the recovery efficiency decreases. Increasing the areal coverage of the bottom water sand resulted in slightly reduced recovery as compared with the confined bottom water sand. On the other hand, increasing the areal coverage of the overlying water sand, that is 9m thick, severely reduced the recovery efficiency of the process as heat is diverted (or channeled) into the "thief" zone. The oil steam ratio (OSR) in this run was below 0.15 m3/ m3 (CWE) after 400 days of injection. When a bottom water layer is present, the BHFP (bottom hole flowing pressure) of the horizontal producer could be operated at or above the pressure of the aquifer to prevent water coning and hence only effecting the heat source slightly.
Reservoir Characterization and Development Plan of the Wasson San Andres Denver Unit Gas Cap
Authors: Coalmer M. S. , Hsu C. F. , Cooper J. C. , Ward J. B. , Voto J. G. , Way K. F. , Valdez R.
Published: December 2007

A plan has been developed to produce the Wasson San Andres Denver Unit Gas Cap reserves without adversely effecting the existing tertiary, CO2 flood of the oil column. This paper: (1) describes the reservoir characterization studies validating hydraulic isolation between the uppermost San Andres gas bearing zones and oil-bearing zones currently under water and CO2 flooding, (2) details the field testing programs, including extensive PTA work and fracture control modeling, that proved technical viability of producing the gas cap without effecting the oil column, (3) details the Wasson field, 3-D, fully compositional, simulation model used for predicting effects on the oil column and developing gas production forecasts and (4) highlights plans for construction and installation of gas gathering facilities adjoined with the existing Denver Unit CO2 recovery plant and/or third party processors. The development plan was approved April 14, 1998 by the Texas Railroad Commission, who agrees that no loss in oil recovery will result from producing the stratigraphic gas-bearing zone termed the First Porosity in the Wasson San Andres formation.
Host Country and Industries Working Together: A Case Study of Indonesia's ONWJ Gas Development
Authors: Suyasa I Made , Saifullah Saifullah
Published: December 2007

In the early 1990's, Indonesia's increasing energy demand required the Government of Indonesia to work closely with the oil companies operating under Indonesia's Production Sharing Contracts (PSC) to resolve the energy shortfall. The numerous fields located in the Offshore Northwest Java (ONWJ) contract area contained almost 2 TCF of certified gas reserves to supply West Java's gas demand. These ONWJ reserves, operated by ARCO Indonesia, Inc., provided a natural fit for the market since they were located in close proximity to Jakarta's high gas demand area. However, expected development costs initially made development of these reserves uneconomic. To overcome this obstacle, ARCO and the Government of Indonesia needed work together to meet both parties’ requirements.

The project was divided into several phases of developments, called Gas Tranches. The first Gas Tranche (Tranche I) was initiated in September 1993 with gas from the KLX/KLY fields to supply 260 BBTUPD of gas sales to PLN (State Electricity Company), with swing up to 325 BBTUPD. At the end of the 11 years contract life, approximately 1 TCF of gas will have been delivered. Following this Tranche I sales agreement, two shorter term contracts were signed: 1) Cilamaya market sales (eastern part of West Java) at 60 BBTUPD for 3 years starting in October 1995; 2) PGN (State Gas Company) sales, called Mini Tranche, at 50 BBTUPD for 10 years starting in September 1997. The Tranche II gas development was then proposed to anticipate additional West Java gas demand.

Since the ONWJ contract area covers an area 160 miles long by 70 miles wide, significant investment was required to build the gas network infrastructure. Wells, well platforms, main pipelines, compressor modules, automation system, and modifications to existing facilities all needed to be installed. With this large capital investment, the gas development was uneconomic under the existing PSC terms. Therefore, special incentives were required from the government.

The Indonesian government and ARCO entered into negotiations to develop these incentives. At the same time, other issues such as the gas development plan, gas markets, supply/sale contractual terms and delivery procedures were discussed and negotiated. To resolve the economic hurdle, ARCO proposed an interest cost recovery incentive, which was one of the possible alternatives available under the ONWJ PSC contract terms. After extended negotiations, Interest Cost Recovery of LIBOR + 1.5% was finally granted by the government to lift the Gas Tranche project's ROR to an acceptable level based on the agreed gas price. The project was then successfully implemented.
Field Testing of Multiphase Meters
Authors: Al-Taweel Ahmed B. , Barlow Steve G.
Published: December 2007

During the past few years, Saudi Aramco has installed and field tested eight different types of multiphase flow meters (MPFM). These newly developed, compact MPFM are targeted for wellhead installation at remote onshore fields and unmanned offshore platforms, where weight and space are major concerns. MPFMs could provide continuous well test data, which would lead to more accurate production allocation and better reservoir management. The application of MPFMs in Saudi Aramco’s production operations, if proven successful, will provide continuous online well production monitoring, and eliminate large conventional test separators, test lines, and offshore test barges. As a result, tremendous economic savings could be realized due to the significant reduction in capital and operating expenditures associated with well testing activities.

The test installations cover a wide range of multiphase applications from over six different oil fields. The objective of the field testing program was to establish the ability of each meter to accurately measure the three production phases (oil, water and gas), and to determine meter reliability in a field environment.

Field test results of the multiphase meters are compared to reference conventional test separators. The paper also presents the current status of multiphase metering technology, and discusses in detail the multiphase metering evaluation program at Saudi Aramco.
Increased Resistance to Proppant Flowback by Adding Deformable Particles to Proppant Packs Tested in the Laboratory
Authors: Stephenson Chris J. , Rickards Allan R. , Brannon Harold D.
Published: December 2007

Numerous proppants, additives and remedial treatments now exist for the control of proppant flowback, yet it continues to be a problem in many oil and gas wells. These approaches to the problem can have certain merits but as a general rule they negatively impact production and are more costly than proppant alone. The importance of these criteria must be balanced against the effectiveness of the chosen approach.

It has been observed in laboratory testing that a deformable proppant material, blended with a typical fracturing proppant, can significantly increase a proppant pack’s resistance to failure under flowing conditions. The fluid exerts a drag force on the structure of the pack and indeed on the individual particles within. These drag forces appear to be much less than the overburden forces that maintain a proppant pack in a stable configuration, prior to fluid flow. In essence proppant packs of typical fracture width, when tested in the laboratory are inherently unstable, unless the individual particles within are anchored or reinforced in some way.

When a deformable proppant is blended into the pack, the deformation between the surrounding proppant grains allows locking of these grains in place. The friction between the grains is effectively increased and thus, the forces required to push the material out of the structure also increase. Addition of deformable particles typically allows the drag forces at failure to be increased by 100% to 300%, while pack conductivity remains better or on a par with the proppant alone, since the material added does not adversely reduce porosity.
Establishment of the Formative Condition of Residual Crack of Rock at Formation Fracturing
Authors: Wenkui Li , Chengshung Wang , Jian Xing
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
New Method for Improving Oil Droplet Growth for Separation Enhancement
Authors: Finborud Anne , Faucher Mark , Sellman Erik
Published: December 2007

Produced water quality is a function of the reservoir conditions, the fluid chemistry and the upstream process. The oil droplet size distribution in produced water is influenced mainly by choke valve pressure drop causing shear effects thereby droplet break down, and further the oil droplets ability to coalesce to larger droplets. Factors preventing coalescence include the droplets negative electrostatic charge, stabilization by surface active components and steric stability caused by fines. The larger the oil droplets in the produced water the easier they are to separate (Stokes' Law). Hydroflokk is a newly developed process for pre-treatment of produced water in order to optimize its separability. In this process oil droplets are subjected to combined chemical and mechanical action to accelerate coalescence and the formation of larger, more separable flocs.

The Hydroflokk system was developed by Norsk Hydro on behalf of the Troll Oil Unit Committee, to be qualified for installation on the Troll B platform in the North Sea. There the Hydroflokk system has been operated successfully since the installation in March 1996. The system has successfully been tested at several offshore platforms with a containerized test unit and has been incorporated in the produced water system for the Troll C platform to go on stream in 1999/2000.
Designing Tomorrow's Compact Separation Train
Authors: Arnold Kenneth E. , Ferguson Patti L.
Published: December 2007

Newly developed compact separation technology may be an attractive alternative to conventional separation methods in certain oil and gas applications. The purpose of this paper is to compare the new compact separators to conventional separation methods and explore the possible applications of this new technology. The size of conventional separators is based on liquid retention time, droplet or settling velocity for gas, and, for three-phase separators, water droplet settling time in the oil phase. Compact separators perform the same function as conventional separators but require a smaller shell. They have great potential where cost savings due to smaller size and lower weight are greater than the cost of more complex equipment. Both the benefits and problems associated with using compact separation techniques for downhole processing, subsea processing, and surface facilities will be discussed in this paper. It is necessary for a design engineer to understand the benefits and detriments of using compact separators so that this new technology may be used effectively in the production of oil and gas.