bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Mud Logging On The Gulf Coast
Authors: Robinson H.C.
Published: December 2007

Effective logging programs are available for wells drilled with non-conductive oil muds. The basic log in such a program is the simultaneously recorded Gamma Ray-Induction Survey. This log provides the primary means for correlation, depth control, and for determination of resistivity values for qualitative and quantitative interpretation.

The Sonic Log, used in conjunction with the resistivity values from the Induction Log, serves as an excellent detector of hydrocarbon-bearing zones.

Determination of porosity is best accomplished with the Formation Density Log. In addition to supplying reliable values of effective porosity, this is the most accurate logging means of determining the lithology of the sand-shale sequences, found in this area.

The use of Induction, Sonic, and Formation Density Logs provides data for complete interpretation of water saturation, effective porosity, and shale content.

Other wireline tools, such as Neutron, Dipmeter, Sidewall Coring, and Wireline Formation Testing, are effective in oil muds.
A Study of Water Coning in the Kaybob South Beaverhill Lake Field
Authors: Graue D.J. , Filgate R.A.
Published: December 2007

Water coning in the Kaybob South Beaverhill Lake Gas Field in West Central Alberta was investigated because production in nearby fields demonstrated that it could be a serious operational problem. The formation water is very corrosive and prohibitively expensive to produce. produce. The water coning phenomenon was studied with the help of a numerical calculation model. The data used in the calculations consisted of fluid and rock data, core analyses, and flow test results. Both vertical and radial variations in permeabilities were included as well as an approximation of non-Darcy flow.

Two field cases where water breakthrough had occurred were history matched with the model. Based on model calculations for 20 other wells, the critical flow rates of 38 producers were estimated.

The results of the model calculations showed that:

(1) critical height is the dominant factor in determining critical flow rate;

(2) the ratio of horizontal to vertical permeability is next in importance;

(3) non-Darcy flow can be approximated in a Darcy flow model; and

(4) non-Darcy flow did not have a strong effect on critical flow rates, at least on wells with critical heights of 50 ft or more.

Introduction

Kaybob South Beaverhill Lake Gas Unit 3, shown in Fig. 1, was developed to meet a required producing capacity of 490 MMcf/D of sour, producing capacity of 490 MMcf/D of sour, condensate gas and a required injection capacity of 260 MMcf/D of dry, recycled gas. Unit 3 contains about 2 Tscf of gas at 4,350 psig and at a depth of about 11,000 ft. About 30 billion bbl of water containing over 200,000 ppm salts underlie the field.

The formation water is extremely corrosive, and the costs of producing it are prohibitive. In nearby Pine Creek field, 10 of the 11 gas wells have been shut in due to water production, and in Kaybob South Beaverhill Lake Units 1 and 2, 11 of the 46 producing wells have begun producing water. It was necessary to replace producing water. It was necessary to replace one gathering-system trunk line in Unit 1 due to corrosion after less than 1 1/2 years on production.

The costs to drill and tie in a new well are between $400,000 and $500,000. Therefore, economics strongly favor producing the wells at low enough rates to prevent water production. In addition, the Alberta Oil and Gas Conservation Board requires operators of gas fields to investigate potential water coning problems and their effect on ultimate gas problems and their effect on ultimate gas recovery.
Fast Water-Coning Evaluation Method
Authors: Bournazel Claude , Jeanson Bernard
Published: December 2007

Many approximate methods have been published for making fast evaluations of published for making fast evaluations of reservoir behavior when water coning is involved.

Based on theoretical or experimental research, these methods usually provide a fairly close approximation of the critical flow rate and the breakthrough time under restricted geometric and drive conditions.

However, when economic necessities make production above the critical flow rate production above the critical flow rate inevitable, the WOR increase versus time or oil production must be evaluated. Heretofore this evaluation has required the use of complicated and costly mathematical models.

This paper proposes a new method combining experimental correlations using dimensionless numbers with a simplified analytical approach based on the assumption that the front shape behaves like a current line, in an equivalent model of different shape.

This method can be numerically processed quickly and easily. It gives a sufficient approximation of both the critical flow rate and the breakthrough time as well as of the WOR increase, the pressure drop, the productivity index and the minimum flow value below which it would be necessary to decrease the flow rate for excluding water production.

The process can be applied to any thick homogeneous reservoir which is horizontally fed.

Conversely, the method can be used for approximately determining the optimum completion and withdrawal rate.

The results obtained using this method have been compared with those from numerous diphasic flow experiments using different-sized physical models. The initial conditions and the fluid characteristics were varied to a large degree during these experiments.

Although the calculations do not take into account the capillary forces existing in the model, there is satisfactory agreement between the different results: agreement which is expected to be sufficient for making a fast prediction and especially for choosing the prediction and especially for choosing the penetration depth. penetration depth. An example is given of how this method is applied to a topical problem. This is followed by a discussion of the influence on water-coning behavior of the different parameters that usually characterize displacement.
Acid Stimulation of Openhole Horizontal Section Behind Prepack Screen Using Coiled Tubing and New Isolation Method
Authors: Koshak W. E. (Skip) , Attah Mike
Published: December 2007

Several techniques are available to remove residual drilling fluid and filter cake from the openhole section behind prepacked screens. This paper describes the use of a new method that isolates the screen and circulates the acid from the screen "toe" back to the "heel" by means of a sliding sleeve. Coiled tubing is used to perform the stimulation operation and manipulate the sliding sleeve.
New Tooling & Techniques Lead to Success of CT Deployed Thru-Tubing Gravel Packs
Authors: Picou R. A. , Hebert L.
Published: December 2007

Due to the development of new tooling and the use of sound engineering coil tubing deployed thru-tubing gravel packs have become an economical and efficient means for the control of sand production.

The authors of this paper have been involved with over forty such jobs in the past two years. The goal of this paper will be to convey the experiences gained in both newly developed component technologies and applications engineering that has been responsible for their overall success.
Project Copernicus – 2nd Generation CT/SHD Rig
Authors: Burge Phil
Published: December 2007

The modern era of drilling using coiled tubing began in the early 1990's and was made possible by the development of enabling technologies such as slim-hoie drilling tools, improvements in tubing metallurgy and horizontal drilling techniques. The industry has recognised that coiled tubing drilling is most applicable for underbalanced drilling, re-entry drilling and through tubing re-entry drilling. Most coiled tubing drilling jobs have been completed using conventional or slightly modified coiled tubing units. A number of hybrid units have been built that incorporate conventional coiled tubing technology with conventional hydraulic jack systems for jointed pipe handling. At the same time as interest in coiled tubing drilling has grown, the interest in slim-hole drilling has waned as the industry recognised that although there was a need for fit for purpose slim-hole drilling units, the capital to build the units was not available. This paper describes a unique rig concept that has been designed specifically for coiled tubing drilling and slim-hoie drilling applications using jointed pipe.
Maximum Set Down Weight and Overpull in Coiled Tubing Simulations
Authors: Suryanarayana P. V. R.
Published: December 2007

Maximum Set-Down weight and Maximum Overpull are important limiting parameters in the design of Coiled Tubing (CT) operations. In the past, these have been calculated using time-consuming iterative approaches that may need 20 or more iterations using a CT forces simulator. We describe here a more efficient approach that allows the computation of these parameters directly, with a very low computational overhead. The procedure is based on the behavior of partial derivatives that describe axial force-transmission along the CT. The procedure and its mathematical basis are discussed, and an illustrative example is presented. Besides being faster, this procedure also provides physical insight into the force transmission in CT. It can also be used to predict the lock-up depth and maximum reach in CT operations.
Laboratory Development and Field Application of a Novel Water-Based Drill-In Fluid for Geopressured Horizontal Wells
Authors: Dobson J. W. , Harrison J. C. , Hale A. H. , Lau H. C. , Bernardi L. A. , Kielty J. M. , Albrecht M. S. , Bruner S. D.
Published: December 2007

Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200 foot production interval, 4.75 inch diameter wellbore in the Gulf of Mexico with a system weight of 13.2 lbm/gal, bottom hole temperature of 185° F., and a 1400 to 1700 psi overbalance. The system functioned very well in both the drilling and completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggests that the well is producing at expected rates with low drawdown pressure.
Production Enhancement Through Aggressive Flowback Procedures in the Codell Formation
Authors: Anderson A.J. , Ashton P.J.N. , Lang J. , Samuelson M.L.
Published: December 2007

Proppant flowback following fracture stimulation treatments continues to be a major concern in many wells around the world. The current trend towards more tip screen out (TSO) and reverse screenout designs has increased the need for better control of proppant flowback under increasingly severe drag force conditions.

Recent studies in the Codell formation have indicated a correlation between load water and polymer recovery on fracture cleanup and subsequent gas production. This paper describes a subsequent twenty-five well study of the specific effects of combining forced closure/reverse gravel packs along with varying flowback rates and choke schedules on load water recovery and normalized gas and condensate production. One of the key issues addressed is the use of aggressive flowback schedules while maintaining proppant flowback control.

Introduction - Codell Description

The Codell is a tight shaly sandstone that produces varying amount of gas and condensate in the D-J Basin of northeastern Colorado (Fig. 1). It is a retrograde condensate reservoir producing below the bubble point. Water production in the subject area is very small, usually 0 to 2 bpd. Formation characteristics are listed in Table 1. Some parts of the field are highly naturally fractured which can cause early screenouts of fracture treatments, but these natural fractures can also aid in production. Directly above the Codell is the Ft. Hayes member of the Niobrara formation, which is a clean limestone. The Ft. Hayes is also very brittle and could be naturally fractured in certain geographic areas. As most of the screenouts have been localized in specific geographic areas, it is believed that the fracture can grow up into the Ft. Hayes resulting in excessive fluid loss and causing an early screenout. A good indication of natural fractures is when a Density-Neutron log shows gas in the Ft. Hayes. Unfortunately very few of these logs have been performed.

Field Study - Fracture Design

Due to the low permeability, the Codell must be fracture stimulated to be productive. Height growth while fracturing the Codell is believed to be predominately downward approximately 300 feet into the nonproductive Carlisle shale. Diversion techniques have been used on many of the wells to try to control the downward growth of the fracture. Fracture treatment designs have ranged from 175,000 to 250,000 total lb. of proppant added, with ramp schedules ranging from 2 ppa to 10 ppa, with an average concentration of 3.4 ppa.

Several papers have been written about optimizing the fracture design in the Codell formation. A statistical study performed by Donovan indicated that proppant volume did not significantly affect the three year cumulative BOE, but that the net pay was the most important factor. Parker et. al. determined that inadequate fracture length and conductivity were the main problems to unsuccessful treatments.

P. 525
Time Lapse Resistivity and Water-Content Changes in Shale
Authors: Morriss S. L. , Chenevert M. E. , Javalagi M. I.
Published: December 2007

An experimental study was made of the change in resistivity as a function of time and distance in a shale sample exposed to a liquid at one end. Two distinct shales were used in the study, Pierre and Wellington. The liquids used included KCl and NaCl solutions as well as deionized water. Resistivity was measured at three distances from the exposed end of the core samples using a six-electrode configuration. Simultaneous measurements of the swelling of the sample were used to calculate water content changes at the same three positions. The mineralogical composition of the shales was determined by x-ray diffraction analysis, resulting in a reasonably good estimate of the amount and type of clay present. Atomic absorption measurements were made on selected samples and the brine to which they were exposed in order to quantify ion movement. The results of this study give some insight into the changes in those properties of a swelling shale which influence resistivity, neutron, and density logs, and the time scale involved in the propagation of those changes away from the wellbore into the formation. While resistivity exhibits the largest relative change of the properties measured, it appears that the depth of investigation of a logging tool must be quite small for the changes to be detectable, for example.
Initial Results from an Acoustic Logging-While-Drilling Tool
Authors: Minear John W. , Heysse Dale R. , Boonen Paul M.
Published: December 2007

This paper presents the initial results from field tests of an acoustic logging-while-drilling tool. Over 60,000 ft of well have been logged with 6.75-in.- and 8-in.-diameter versions of the tool. Various types of formations were encountered with compressional slowness values ranging from 55 µsec/ft to 170 µsec/ft. The tool is configured as a borehole-compensated device; transmitters are located on opposite sides of an array of four receivers. An ultrasonic standoff transducer provides a tool-to-borehole wall distance measurement for data quality evaluation and processing.

Slowness values are computed downhole using real-time waveform processing. Full-waveform data are stored for retrieval and re-processing at the surface. Interactive processing software allows an engineer to reprocess log intervals of poorer log quality and improve the slowness log computed downhole. Downhole-processed and post-drilling-processed slowness logs are compared, and generally show close agreement. These logs also agree well with wireline slowness logs.

Rugose boreholes and attenuating formations can reduce waveform quality. A new rapid-fire technique acquires multiple estimates of slowness as the drillstring rotates through only a fraction of a revolution, and improves slowness quality in rugose boreholes.

Shear-wave energy is clearly apparent in most waveform data. Waveforms can be processed to yield both shear and compressional slowness values. These can then be used to estimate porosity, compute elastic moduli of the rock (for example, Poisson’s ratio, Young’s modulus, bulk compressibility, and shear modulus), and to compute synthetic seismograms for correlation with seismic profiles. Some of these applications of compressional and shear slowness data are discussed with examples.
Transient Analysis To Locate and Characterize Plugs in Gas Wells
Authors: Hasan A.R. , Kouba G.E. , Wang X.
Published: December 2007

We propose to use pressure transient analysis to indicate the location of a flow restriction in a gas well and to characterize such a blockage. We have developed a transient simulator for a gas well with a single partial blockage at any location in the flowline. The early-time wellhead pressure drop is influenced by the volume reduction due to the plug and its location while the late-time steady flow wellhead pressure drops give an indication of the severity of the plug. Thus, the early-time and late pressure response data can be used for blockage detection.

Our study found that the thickness, the length, the location, and the roughness of the plug strongly influence the wellhead pressure response. Of these factors, the extent of reduction in channel diameter (due to plug thickness) has the most effect. In addition, we found that the flow rate at which the test is run has a pronounced effect on both early and late time wellhead pressure transients. We also noted the influence of reservoir pressure on gas density and velocity, which in turn, have some effect on the wellbore storage and the frictional pressure drop. Our study showed that wellbore deviation did not have any appreciable effect on wellhead pressure drop. Geothermal gradient was also observed to have negligible effect on wellhead response. In addition, we found that for most scenarios, the transient pressure response characteristics for off-shore production are similar to those for on-shore wells. Thus, the analysis presented in this report is suitable for off-shore wells as well.

Introduction

Problem Statement. Unwanted flow restrictions are often a fact of life in the oil field. Potential causes for the development of these restrictions are numerous. Fluid properties, coupled with unfavorable pressure and temperature conditions, may lead to formation and deposition of wax, hydrate, asphaltene and scales on the pipe wall. Pipeline configurations could also lead to deposition of sand, buildup of liquid, or formation of vapor lock. Mechanical causes of flow restrictions include stuck spheres or pigs. Other possibilities include pipeline deformation from thermal stresses or mechanical damage.

Once a blockage has occurred, the cause of the restriction is not always easily discernable. Delays in taking appropriate remedial action can cost lost production and could also lead to the development of hazardous situations. Administering the wrong remedial action to remove the plug can be very costly and may even make matters worse.

Often, the type of blockage can be determined if the plug location is known. For instance, a pipe may collapse at a road crossing, or the temperature and pressure conditions in the line may be conducive for different solids deposition over separate but well defined regions. Knowing the blockage location could provide the additional information needed to determine the type of blockage with sufficient confidence to begin remedial action.

P. 653
The Auger Platform: Debottlenecking and Expansion Of Fluid Handling Facilities
Authors: Judd T. R. , Wallace C. B.
Published: December 2007

AUGER, Shell's first Tension Leg Platform (TLP), was installed in 1994 in 2860 feet of water in the Gulf of Mexico. The platform was designed to process 40 MBPD of oil, 100 MMSCFD of gas, and 25 MBPD of water. For most of its operation, the surface fluid handling facilities have proven to be the primary constraint limiting increased production.

Through innovative debottlenecking and expansion of the surface facilities, Auger production rates have recently increased to more than 72 MBOPD and 150 MMSCFD of gas. Further plans are underway to ultimately increase the total platform capacity to 100–140 MBOPD and 300–400 MMSCFD.

This paper will present the original platform design, describe the constraints on the facilities due to higher than anticipated well flow rates and surface temperatures, and discuss the steps taken to reduce the constraints and resolve most problems. These problems include. (1) poor gas/liquid separation efficiency in high pressure separators, (2) excessive natural gas liquid (NGL) condensation in the gas export pipeline, (3) gas dehydration system limitation due to high rates and surface temperatures and (4) other facilities engineering related problems.
Laboratory Investigation of Damage From Guar Gum Base Gels
Authors: Kolb A.K.
Published: December 2007

The damage effect of a guar gum water-based fracturing fluid has been investigated on sandstone and limestone formations furnished by Cleveland Quarries Co. of Ohio. The permeability and porosity of each core was measured before treatment using a high precision micro-permeameter and a high-precision permeameter.

Each core was first saturated with 2% NaCl solution flooded with nitrogen gas and its permeability and porosity were recorded as K and phi, respectively. All samples were then treated with the base-fluid (distilled water) followed by a similar measurement of their permeabilities and porosities. The same cores were once again treated with a guar gum based porosities. The same cores were once again treated with a guar gum based solution ranging in concentration from 20 lbs/1,000 gal to 40 lbs/1,000 gal and their respective permeabilities and porosities were also computed after the treatment. Similar tests were run on the cores by adding 2% CaCl4 and 10% NaCl respectively on the different concentrations of guar. The results revealed that in all cases the core have been damaged and that the magnitude of the damage is not always proportional to the concentration of the guar gum; and in most cases the addition of 2% CaCl2 to the gelling agent solution gave better results than the addition of 10% NaCl. It can also be concluded that the treated guar gum will be more recommended for fracturing limestone formations, while its damage effect for sandstone formations is comparatively high.

Introduction

The use of chemicals as gelling agents in hydraulic fracturing stimulations include both natural and synthetic products. These products fall into the class of high molecular-weight polymers. Synthetic chemicals used in gelling water are very costly and have a tendency to gel more rapidly and produce the same apparent viscosity at less concentration than the natural produce the same apparent viscosity at less concentration than the natural products such as guar gum. products such as guar gum.
Problems Encountered In Drilling and Completing Deep Wells
Authors: Eaton Ben A.
Published: December 2007

Problems encountered in drilling and completing wells to 15,000' and below are reviewed in this paper. Statistical trends in deep well drilling indicate that increasing numbers of such wells will be drilled each year. Problems associated with this activity are similar to those of past shallow drilling. However, these problems are more severe and much more expensive than those in the past.

The role of a drilling coordinator, with regard to the development of sound, workable drilling plans, is discussed. A method of well planning is presented that, if used, will reduce the frequency of expensive problems in deep drilling.

Many of the recurring problems involved in deep drilling are discussed, as are some of the more recent engineering solutions to these problems. This discussion centers not only on the drilling problems, but on some of the completion problems, but on some of the completion problems as well. One such problem involves problems as well. One such problem involves the attempted completion of wells drilled below depths where commercial production is extremely unlikely to be found. A means of avoiding this problem is also discussed.

It is concluded that a great majority of such drilling and completion problems could be eliminated in most cases by better planning, and better trained on-site rig planning, and better trained on-site rig supervisors carrying out the previously agreed upon well plans.

Introduction

Statistical trends in the drilling of oil and gas wells in the United States indicate that the number of deep wells is increasing and that the yearly average depth of these wells is increasing. There are two primary reasons for these trends. The first reason is the fact that there are fewer good shallow prospects to be drilled, and secondly, a real energy crisis is fast approaching in the United States. To avoid this energy crisis problem, operators are spending vast quantities of monies to drill what we will call "deep wells".

For the purpose of this paper, a "deep well" is defined as a well drilled below 15,000' for the purpose of exploring for and producing of oil and/or gas. The first such well was drilled in 1939, but the real increase in this activity started in the 1950's. The statistical trends for the yearly average well depth and number of wells drilled to at least 15,000' are shown in Figure 1.
Developing Block 2 Angola: A Multi-Dimensional Approach to Managing Development Risk
Authors: Morris Ronald L. , Romero Rocky R.
Published: December 2007

This case study focuses on a $380 million project involving the development of eight new offshore fields in Block 2 Angola, which became a success story despite facing major obstacles during early phases of the project. This study highlights how a multi-dimensional approach to managing risk and uncertainty, coupled with excellent cooperation with Partners and government, can lead to an economic success.

With the interruption of the Angolan peace process in 1992, Block 2 became directly affected during the construction phase of the project. For a two year period and until the signing of the Lusaka Peace Accords in 1994, which reestablished a cease-fire in Angola, mitigation of risk and uncertainty became the primary driver in completing this project. As a minority shareholder in Block 2, Texaco - Angola (Texaco Panama Inc. - Angola) as Operator needed to gain consensus among all its Partners and government for a revised development plan, taking into account some very divergent views of the risks facing the partnership. Ensuring the security of personnel, continuity of income, and maintaining sound project economics were required to gain the consensus needed to move ahead. A complete re-design of the development concept ensued while in the construction phase. The result was that this project was completed some 3 years later with acceptable economics.

Unconventional and innovative design, financial hedging and project management solutions will be highlighted to illustrate how this was accomplished.
Dehydration of Crude Using Electrostatic Treaters: Development of Design and Operating Guidelines
Authors: Khatib Z. I.
Published: December 2007

Electrostatic treaters have been used at various Shell fields to dehydrate light, medium, and heavy crudes. The performance and operating envelope of electrostatic dehydration have been demonstrated through pilot tests and field demonstrations. Oil throughputs of 200-300 BOPD/ft2 of grid area for light crudes (30-35° API gravity) and 10-20 BOPD/ft2 for heavy crudes (11-14° API gravity) were shown to be adequate for producing pipeline-quality crude. Implementation of these design rates could lead to tangible capital savings in reduced size and dead weight (important to tension leg platforms) as well as in reduced operating costs.
Well Control Incidents are CRINE and Safety Opportunities
Authors: Hamilton T
Published: December 2007

The United Kingdom Health and Safety Executive (The HSE) engages in scientific activity mainly to develop its understanding of the hazards, to assist in the formation of standards needed for regulation and to enable it to challenge and form independent judgements on industrial activity that may be unsafe. One focus of attention over several years has been oil and natural gas well control. In 1992 The HSE Offshore Safety Division (OSD) embarked on a well control incident assessment programme using a new computer simulation tool and data on specific oil based mud incidents supplied by Operators. This phase of a larger ongoing programme set out to prove and exploit the new tool and insights into kick fluid mechanics produced from earlier research projects to achieve safer well control.

OSD’s programme is focused on the kick control phase in well control incidents where the risk of escalation is highest. After proving that the simulation tool could model actual field experience accurately in selected incidents the programme was extended to show a wider range of incidents could be modelled. The way is now open to sharing experience by sharing technical details of events, actions and behaviour of fluids in wells during incidents. Sharing experience more widely is a practical and effective way of improving awareness and safety performance. In addition it should bring cost saving in a similar way to that heralded by the Cost Reduction in the New Era (CRINE) programme. Step changes in safety and cost reduction performance require similar changes in culture to secure success.

The paper reports the results of collaboration with industry between 1992 and 1995. It describes experience in modelling from field data, incident evaluation and developing communication tools and then looks forward and describes the aims and objectives of current work in the main programme.
Risk Assessment of Hydrocarbon Releases during Workover and Wireline Operations on Completed Wells on Offshore Platforms
Authors: Edmondson J. N. , Hide D. K.
Published: December 2007

Safety Regulations in the UK require operators to demonstrate that the risks to workers from well operations on offshore platforms have been reduced to the lowest level that is reasonably practical. Each offshore platform in the UK has a safety case which includes a quantified risk assessment of well operation hazards with the potential to cause a major accident.

Assessment of the safety cases by the UK Health and Safety Executive (HSE) showed that few operators have specifically analysed risks resulting from well workover or wireline operations, regarding such risks as subsumed within general blowout risks. Where workover/wirelining have been considered separately, the risk estimates have been determined from average worldwide historical hydrocarbon release frequencies and not by analysis of particular operations being carried out on a specific platform. The prevalent conclusion from such risk analyses is that the contribution of workover/wireline risks to the total platform risk levels is very small. In order to evaluate whether such a conclusion is necessarily valid in all cases, HSE undertook a study to establish a method for estimating workover/wirelining risks for a number of different types of platform.

This paper describes the method used by HSE to assess the risk of hydrocarbon releases during workover and wireline operations. The workscope was restricted to completed wells on offshore platforms. The method is based on a detailed analysis of all the different potential failure modes associated with the various well intervention operations carried out on these platforms. The failure mode analysis results are then used to estimate the significance of these risks relative to risks from other activities on these platforms and to assess where the use of average historical release frequencies could be justified and where additional analyses are necessary. The study also provides a mechanism for identifying those workover/wirelining operations which are predicted to give rise to the highest risks and for which risk control measures should be reviewed very closely.
Application of Non-Conventional Wells to Infill
Authors: Mochizuki Satoshi
Published: December 2007

The objective of this study is to find the effectiveness of non-conventional wells as infills under miscible gas and WAG (water-gas alternating injection) floods. Ten types of non-conventional wells are investigated and the results show that the performance of non-conventional wells strongly depends on types of wells, flood size, operational conditions, drive mechanism and reservoir characterization. Therefore, these factors must be carefully considered in optimizing the selection of wells and operating scenarios
Structural dynamic monitoring on Vega platform: an example of Industry and University collaboration
Authors: Musso A. , Spadaccini O. , Vignoli A.
Published: December 2007

Dynamic study of Vega platform has been carried out to estimate the significant uncertainties connected with mathematical modelling and evaluate their influence on the predicted structural response. The comparison between the design hypotheses and the structural response has been performed using the informations collected by existing monitoring system of the platform. The modal analysis, computed for a range of the significant parameters, has shown the correlation between damage states and changes in the dynamic characteristic of the jacket, which are fundamental elements to evaluate the structural response of the platform after a enviromental event. The possibility to associate the variations of dynamic response, collected by appropriate program of continuous or periodic monitoring, to the fatigue life of the welded joints and to structural collapses can be of great help to the ordinary techniques of inspection. This possibility, besides, can allow an appreciable reduction of the expensive conventional underwater inspections, without interferring in the normal operativity of the platform.
Multiple Frac-Pack Stimulations of Deviated, High-Permeability Water-Source Wells
Authors: Finley D. B. , Chong K. K. , van Domelen M. L. , Kaweeyanun P.
Published: December 2007

This paper presents a case history of technology applied to perform multiple ffac-pack treatments in three deviated water- source wells in Central Thailand. Each of the three wells had been sidetracked from its original completion because of previous production problems. The multiple target zones in these wells were soft, high-permeability, unconsolidated sandstones that lacked barriers for fracture containment. Given these conditions, ffac-pack completions were designed and implemented. Frac- pack treatments are small hydraulic fractures designed for relatively short fracture lengths and high conductivity. The ffac-pack treatments, which minimize the effects of near-wellbore damage, are generally followed by the placement of a conventional gravel- pack to ensure that sand production does not occur. This type of completion technology, relatively new to the Asia-Pacific region, should be considered in areas where conventional sandstone acidizing and gravel-packing operations have yielded unsatisfactory results.

Technology and operational considerations for this type of completion scheme were as follows: possibility of multiple hydraulic fractures resulting from long perforated intervals in the deviated wellboresapplication of sand slugs to reduce/eliminate excessive near-wellbore friction pressureson-site minifrac analyses performed immediately before each frac-pack to optimize the main treatment designplacement of sand plugs for zonal isolation in lieu of mechanical, drillable bridge plugs to reduce rig time while the treatments were performed

This paper presents the technology applied to address each of the previous considerations and water production results to date for each of the three wells.
Reservoir Simulation Modeling of Natuna Gas Field for Reservoir Evaluation and Development Planning
Authors: Fenter D. J. , Hadiatno D.
Published: December 2007

In the development planning studies of the Natuna gas project, a three-dimensional, two-phase reservoir simulation model of the Natuna gas field was used for evaluation of the gas reservoir and as a planning tool. A detailed sequence stratigraphic study of the gas field that incorporated seismic, well log and core data provided the basis for the geological model used in the reservoir simulation model. The objective of the development planning studies was to determine production well locations, production well drilling schedules, the total number of wells required, the timing for the installation of wellhead compression equipment and the gas production profile for the field as a function of time. The reservoir is estimated to be able to sustain a 2,400 million standard cubic feet per day (Mscf/d) methane production rate for 30 years or more.
Planning and Construction of Storage Caverns in Salt Deposits
Authors: Wockenfuss A.
Published: December 2007

Difference in the drilling concept between wells planned for underground storage purposes and those for crude oil or gas are discussed. The completed wells are investigated by means of a series of logs to analyse the quantitative mineral composition of the salt. The method avoids most of the expensive core drilling. The results gained by the computer-calculated interpretation of the log have been confirmed by observations made during the leaching process.

The well-known mineral composition enable the planning of a detailed leaching program for every envisaged cavern. It contains among other things the number of washing stages in every cavern, the intervals for sonar logging and the time required to create the desired volume.

Together with a description of the technical installations used a report on experiences with material and equipment is given.

The performance and supervision of the leaching process is discussed, especially the different methods to determine the cavern volume created. It has been found that, depending on the shape of the cavern, major differences in volume sometimes occur due to the different calculation methods used.

To enable permanent control of shape development of the cavity during the leaching process, a procedure has been introduced using the field data obtained.

Introduction

For many years storage caverns for natural gas and LPG in salt deposits have been built and used, especially in USA. In Germany the first cavern for seasonal storage of butane with a capacity of about 125,000 bbls. was completed in 1963.

In recent years an ever increasing number of caverns have been planned and built for storing crude oil or fuel oil. Especially since several European countries have promulgated laws obligating petroleum refiners to maintain petroleum stocks, a growing interest in this type of storage has become apparent. In case of favorable geological and topographical conditions storage in caverns is superior to all other methods from an economic standpoint. Since 1968 various projects for creating storage capacity to meet the stockpiling obligation are under construction in North Germany.

In the following the storage project of Sottorf near Hamburg serves as an example to report on experience gained and methods used during the construction of this project.
How To Optimise A Dynamic-Stationing System
Authors: Zunderdorp H.J. , van der Vlies J.A.
Published: December 2007

After a short description of the general principles of dynamic-stationing systems, a method principles of dynamic-stationing systems, a method of optimising the controller is described. In the past, dynamic stationing has been regarded as a past, dynamic stationing has been regarded as a solution only for deep-water operations. Complete simulation of the behaviour of the vessel, the controller and the thruster units under the influence of current, wind and irregular waves now enables us to optimise the system in such a way that stationing is even possible in as little as 200 ft of water.

A description and some results of such simulations, which can be performed equally well on digital and hybrid computers, are given. As a result of these studies, the need for two further improvements became apparent. The first is a form of filtering technique to remove the cyclic component from the steering signal of the thrusters, so allowing improved control, higher efficiency and less wear and tear on the thrusters. The requirements for such filters are given. The second improvement is the feeding forward into the control system of a signal proportional to the wind force to enable quick response to wind gusts, so reducing Use deviations from location that would otherwise result.

Introduction

Very few dynamically stationed vessels have been built to date, although the principles involved are very simple. The vessel is kept on station with the aid of a servo system, rather than by mechanical means. To accomplish this, the deviation from Be origin is measured and translated into command signals, which activate propulsion units in such a way as to compensate for the deviation.

Thus this is in fact a normal control system, of a type used in many engineering fields. The difference between this and normal control applications, however, is the size of the mass to be controlled and the magnitude of the outside disturbing forces. These forces are delivered by wind, waves and current; the first two of these are irregular in character and only the third one remains stable over a restricted period of time. The sum of these forces may be larger than the restoring forces that can be delivered by the propulsion units, and it is only because of the cyclic nature of (especially) the wave forces that control is still possible. It will be clear that the nature of these possible. It will be clear that the nature of these forces will influence the design of the control system substantially.
Pipeline Gas Reserves And Availability
Authors: Buck J. Randolph
Published: December 2007

Buck, J. Randolph, Member AIME, Northern Natural Gas Co., Omaha, Nebr.

Publication Rights Reserved

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

This paper is directed to the significance of gas reserves and the availability of such reserves to natural gas pipeline companies. Various uses for these computed data within a gas supply department and a transmission company as a whole are suggested.

Sources of basic data, the treatment of gas well and casinghead gas, the development of area specialists, together with general procedures followed in the active prosecution of reserves work are indicated.

A distinction is made among the terms availability, deliverability, and potential. Each may be considered from the individual well, total field, gathering system, or total company points of view.

The problem of gas well stabilization, with particular regard to the ability of wells to maintain certain flow rates under continuous production, is emphasized from the standpoint of the regulatory necessity for a pipeline company to demonstrate an adequate gas supply to meet requirements of the presently proposed or future sales. Very practical problems are involved in the extreme case of low deliverability and high reserves on a per-well basis. The demonstrated difficulty of a pipeline company to maintain a 12-year availability life without creating a condition of oversupply, or bulge gas, is reviewed.

General requirements and procedures followed in a certificate application proceeding before the Federal Power Commission are briefly discussed. Meanings for the terms "reserve life index" and "availability life" are included with a review of the effect of an unrealistic availability life control on the industry.

Introduction

In the state of Texas, petroleum engineers qualify themselves in the field of petroleum and natural gas. Although oil and gas constitute one basic industry, many engineers, particularly the older ones, have devoted the large portion of their time and effort to problems relating to the production of oil. The realignment of a sizeable proportion of the emphasis to problems peculiar to gas has been a development of the past decade wherein the marketability of gas has increased tremendously. The continually expanding sales of gas has been achieved by the pipeline segment of the total oil and gas industry in a complex process involving producers, consumers and certain regulatory bodies. Because of the present magnitude of the gas industry in light of its more recent rapid growth, it is believed not too late to set down a synopsis of how and why gas transmission companies actively engage in and rely upon reserves and availability studies.
Interpretation Of The Results Of The Back Pressure Testing Of Gas Wells
Authors: Govier G.W.
Published: December 2007

Publication Rights Reserved

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

The origin and limitations of the conventional and empirical equation for the interpretation of the results of back pressure tests on gas wells are discussed. Difficulties in data interpretation arise from many causes., including lack of flow stabilization,, uncertainties in connection with the friction calculation, and the effect of turbulence near the sand face in the reservoir.

A procedure is developed to account for the turbulence effect. This is based upon the theoretical equation for laminar steady-state flow and current knowledge of turbulent steady-state flow. The procedure involves the expression of the equation for combined laminar-turbulent steady-state flow in terms of a turbulence contribution factor. This factor is shown to be dependent mainly upon the flow rate per unit of pay thickness and the reservoir permeability.

The method of interpretation permits the use of judgment based upon the theory and present day understanding of laminar-turbulent flow and is considered an improved method for interpretation of stabilized flow or isochronal data, particularly in cases where high flow rates per unit of thickness are encountered.

Introduction

Since 1935 when E. L. Rawlins and M. A. Schellhardt of the U. S. Bureau of Mines published their Monograph 7, their methods have served as the primary guide to the gas industry in the conduct and interpretation of back pressure tests on gas wells. Over the years an increasing awareness of the need for carefully calibrated equipment and meticulous care in the conduct of the field test has developed. The extreme importance of conducting the test either under "stabilized" conditions or as an isochronal test has been clearly shown by Cullender and others. Improved theoretical understanding of the calculation of bottom-hole pressures from measured tophole pressures, together with reliable compressibility factor data has permitted modifications and improvements in the procedures of Monograph 7 for these calculations. The important role of the relative roughness of the flow string in determining the friction component in the calculation of the flowing bottom-hole pressures has been realized and methods superior to that of Monograph 7 [involving the Weymouth friction factor correlation] have been developed and are in increasingly common use. [Notwithstanding these better methods, however, lack of knowledge of the actual roughness of the pipe remains a serious practical problem.]