bluuebunny/crossref_metadata_2025 huggingface dataset:
Determination of Gas Well Stabilization Factors in the Hugoton Field
Authors: Mathur Shri B.
Published: December 2007

On the basis of a 72-hour shut-in pressure as an average reservoir pressure, the method described here can be applied satisfactorily pressure, the method described here can be applied satisfactorily to determine the stabilization factors for different wells in the Hugoton field, and in fact for wells in any tight, dry-gas, low-pressure reservoir.

Introduction

The stabilization factor can be defined as the ratio of a well's performance under pseudo-steady state conditions to the well's performance at the end of a given length of flowing time. When a gas well is drilled, it is necessary to predict the stabilized performance of each well for the orderly exploitation of gas reserves, future availabilities of gas, future gas contracting requirements and future planning of operating facilities. When a gas well is producing from a highly permeable reservoir, only a short period of time is required for steady-state conditions to be approximately established throughout the drainage area. Low permeability reservoirs exhibit "slow stabilization" and require long periods of flow and shut-in time for determination of stabilized conditions.

The conventional way to determine the stabilization factor for wells in the Hugoton fields of Kansas, Oklahoma and Texas is to shut in the well, which was previously flowing at stabilized conditions, for previously flowing at stabilized conditions, for maximum pressure buildup. The ratio of pressure buildup at the end of 72 hours compared with the maximum pressure buildup is then designated as the stabilization pressure buildup is then designated as the stabilization factor for that well. This requires that the well be shut in long enough for maximum pressure buildup, which may take a month or more.

Because there are hundreds of wells in the Hugoton fields on which it is not practical to conduct long buildup tests, a method is needed for determining stabilization factors based on information obtained from short term shut-in tests.

The objectives of this paper are (1) to present a theoretical development of a method of determining the stabilization factor from short term tests; (2) to present an application of the developed (3) theory to field present an application of the developed theory to field data; (4) to verify its validity by comparing the results with those obtained by the conventional long duration buildup method; and (5) to determine if the stabilization time and hence the stabilization factor changes during the life of a well.

Mathematical Description of the Method

The solution for the diffusivity equation frequently used for a true infinite medium has been referred to as the point-source solution and can be expressed as a logarithmic function.

which may be rearranged to read

where

k= ln ------ + 0.809, crw2

JPT

P. 1101
Identification of Aluminum Scale With the Aid of Synthetically Produced Basic Aluminum Fluoride Complexes
Authors: Shuchart C. E. , Ali S. A.
Published: December 2007

Aluminum scaling can be a problem following HF acidizing. In this paper, a series of synthetic aluminum scales was prepared and identified. The aluminum compounds of a field scale were identified with similar procedures. Recent field work showed that the use of acetic acid in the HF acidizing sequences significantly decreased scaling. The role of acetic acid is discussed on the basis of laboratory support of these field data.
A Deepwater Riser Emergency Disconnect Antirecoil System
Authors: Hock C.J. , Young R.D.
Published: December 2007

During drilling in deep water, very high tensions must be used to control the riser, so a large amount of energy is stored in the riser and tensioning system. If the riser and stored energy are not controlled during an unplanned disconnect of the riser from the subsea blowout preventer (BOP), which would result if a dynamically positioned vessel drifted off location, the rig could be seriously damaged and the costly riser could be lost. This paper presents the design processes, installation, and testing of the riser emergency disconnect antirecoil system added to the drillship Discoverer 534 as part of the upgrade to 6,000-ft water depth. The system controls the riser and its tensioning system during and after an unplanned disconnect. This paper views the initial design analysis of the riser and tensioning system using an existing computer modeling program. It presents modifications to the computer program to simulate a disconnect with mud in the riser and using the telescopic-joint latching riser capture system. We discuss the hardware and the problems experienced during the design and computer analysis phases and their unique solutions. We describe important details of the installation in the shipyard and during sea trials. We discuss the full-scale instrumented emergency-disconnect test of the system in 3,700 ft of water and the results of the test. Finally, we present the post-test fine tuning of the computer modeling and predictions for deepwater/high-mud-weight disconnects.

Introduction

When the upgrade of Discoverer 534 to drill in 6,000 ft of water in the Gulf of Mexico began, knowledge gained during years of record-setting deepwater drilling by the Discoverer Seven Seas was used in guiding the project. Engineering studies made during the upgrading of the Discoverer Seven Seas indicated that a riser antirecoil system was needed to control the riser during and after an unplanned disconnect from the subsea BOP. Control of the energy stored in the marine riser and its tensioning system was necessary to latch it to the floating vessel mechanically, thereby preventing riser loss.

The Discoverer 534 and the Discoverer Seven Seas are sister drillships with essentially the same hull. However, their riser and riser tensioning systems are different. The Discoverer Seven Seas has an 18 5/8-in.-OD riser system; the Discoverer 534 has a 21 in.-OD riser. The type of drilling planned for the Discoverer 534 called for heavy weight drilling fluids of up to 16 lbm/gal. The Discoverer Seven Seas typically used much lighter muds. These differences meant that, while the experience gained from operating the Discoverer Seven Seas would be invaluable, the engineering and the design of its antirecoil system could not be directly applied to the Discoverer 534. With the Discoverer Seven Seas as a starting point, the design of the Discoverer 534 began.
Determination of True Hook Load and Line Tension Under Dynamic Conditions
Authors: Luke G. R. , Juvkam-Wold H. C.
Published: December 2007

Theoretical and experimental studies show that true hook load depends on sheave friction, direction of block movement, and previous movement history. In some cases, actual hook load was observed to be up to 19% higher than the load predicted by the method currently used in the oil industry.
The Influence of Chemical Potential on Wellbore Stability
Authors: Hale A. H. , Mody F. K. , Salisbury D. P.
Published: December 2007

An experimental investigation was begun to understand fundamental borehole stability mechanisms. This laboratory study was directed toward understanding why and how drilling-fluid chemistry affects borehole stability. The ability of drilling-fluid chemistry to alter shale mechanical behavior and the borehole stress state as a result of shale water content alteration was investigated. Experimental results demonstrate the influence of various drilling-fluid parameters (e.g., salt concentration, salt type, and diesel/water ratio) in oil-based drilling fluids on the water content, compressive strength, and mechanical properties of five shales. The influences of temperature and drilling-fluid exposure time on shale strength alteration also are addressed. The results are explained on the basis of chemical potential differences between oil-based drilling fluid and shale. The change in the shale water content caused by these differences is identified as the predominant factor leading to alteration of shale mechanical behavior and hence borehole stability.
A Simple Approach to Optimization of Completion Interval in Oil/Water Coning Systems
Authors: Boyun Guo , Lee R. L -H.
Published: December 2007

An analytical solution is presented to estimate the maximum water-free production rate (critical oil rate) that considers the effect of limited wellbore penetration on the oil productivity of the well. To maximize the critical oil rate, an optimum wellbore penetration into an oil zone is determined theoretically. This analytical solution shows that the optimum wellbore penetration into a pay zone is less than one-third the total pay-zone thickness.
New Coiled-Tubing Cementing Techniques at Prudhoe Developed To Withstand Higher Differential Pressure
Authors: Krause R. E. , Reem D. C.
Published: December 2007

The successful hydraulic fracturing program at Prudhoe Bay would not have been possible without an effective coiled-tubing-unit (CTU) cement-squeeze program. Many fracture stimulation candidates were wells that had been squeezed previously. Therefore, squeezed perforations were exposed to higher differential pressures during fracturing operations than normally were seen at Prudhoe. At the outset of the fracture stimulation program in 1990, squeeze perforations failed when subjected to fracture job pressures. It quickly became clear that more aggressive CTU squeeze techniques resulting in stronger squeezed perforations would be necessary if the Prudhoe fracture program were to achieve its goals. Arco Alaska Inc. implemented a more aggressive CTU squeeze program in the Eastern Operating Area (EOA) in mid-1990. This paper documents the results of the new squeeze program, in which increased surface coiled-tubing squeeze pressures from 1, 500 to 3, 500 psi for 1 hour were used. More resilient, acid-resistant latex cement also became the standard in late 1990 for squeeze cementing. Implementation of this program has resulted in a squeeze success rate approaching 90%.
Redesigned Ester Single-Well Tracer Test That Incorporates pH-Driven Hydrolysis Rate Changes
Authors: Wellington S. L. , Richardson E. A.
Published: December 2007

The rate of alkyl ester hydrolysis was found to be sensitive to the pH changes that occurred during application of the single-well tracer test (SWTT) in both sandstone and turbidite reservoirs. Detection methods, an improved test sequence, and the detrimental consequences that this variable can have on oil saturation determination are discussed.
Some Pulsed Neutron Logging Contributions To Improved Formation Evaluation
Authors: Fons Lloyd
Published: December 2007

Pulsed neutron logging, because it can be performed in cased wells, is supplying previously unobtainable information for evaluating reservoirs. When spaced in time, these logs make it possible to deduce the nature of water encroachment and hydrocarbon depletion at any stage in the producing life of a well.

Introduction

Hydrocarbon volume and geometry within a reservoir must be determined before the efficiency of hydrocarbon production can be judged. This requires a more thorough analysis than is possible during the early development of a field. During this early period many assumptions (universally based on incomplete sampling) are made for a number of factors including water saturation, reservoir boundaries, average reservoir thickness and ultimate recovery efficiency. Data obtained by initial drilling, well logging and production tests are the primary tools for early evaluation of the reservoir. Production history is inadequate in the initial stages of pool development, but as a field is developed and more wells are logged, more data are collected, and useful production history accumulates. The production trends may change depending upon rate of production, drive mechanism, state of reservoir development, porosity and permeability distribution, and efficiency of completion methods. All in all, production history is regulated by a complex set of conditions, some of which have been rather arbitrarily established by the engineer.

It is commonly assumed that the formations exposed by the wellbore of the discovery well are representative of the subsurface of the entire location (or lease). Each log of a subsequent well will measure the physical properties of the formations immediately surrounding that particular well. The formations exposed are generally thought to extend laterally and continuously to connect with counterparts in adjacent wells. Preferential watering-out of individual strata within a formation commonly occurs.

Pulsed Neutron Logging

Pulsed neutron logging (PNL) has been well described in the literature.1-6 It is relatively insensitive to commonly occurring changes in borehole size and fluid type,7 and is well suited for use in cased wells. The casing of a well before "open-hole" logs are run no longer precludes the high probability of efficient formation (and well) evaluation by logging methods. The resulting cased-hole logs, when used with companion services such as neutron or interval-time logging through casing, will supply much the same information as is obtained from standard open-hole logging programs.
New Chemistry for the Placement of Chromium(III)/Polymer Gels in High-Temperature Reservoirs
Authors: Lockhart Thomas P. , Albonico Paola
Published: December 2007

Coordination chemistry concepts have been used in the development of Cr+3/polymer solutions that meet the delayed-gelation requirements for in-depth treatment of high-temperature reservoirs. Use of the malonate complex of Cr+3, Cr(malonate)3)3, provides gelation delays at elevated temperature much greater than those obtained with either the hydrated Cr+3 ion or Cr(acetate)3. Inclusion of additional, uncomplexed malonate ions in the formulations provides a means for further, and predictable, extension of the gelation time. The gelation delays obtained over the temperature range of 90 to 135 °C are equal to or greater than those that can be achieved with the best gelation delay technologies described previously.

The dependence of the gelation time on temperature, pH, and the Cr+3 and malonate ion concentrations has been investigated. Preliminary results indicate that the thermal decomposition of the delaying ligand, malonate, plays an important role in determining the gelation rate. The use of a Cr+3 complex of relatively low toxicity rather than the carcinogenic Cr+6 ion to control gelation rate is an amctive feature of the new technology.
Reservoir Barrier and Polymer Waterflood, Northeast Hallsville Crane Unit
Authors: Moore Joe K.
Published: December 2007

As a result of field-wide polymer injection, recovery in this unit exceeded by 40 percent the estimated recovery for an ordinary waterflood, and at an average cost of just 33 cents per barrel.

Introduction

The Northeast Hallsville Crane unit operated by Hunt Oil Co. was one of the first field-wide applications of a polymer flood. Since this field is well along in the final stages of be flood project, it has been possible to look at the effects of polymer injection and draw some conclusions about the use of these chemicals. The original purpose of polymer use in this project was to create a viscous barrier between the oil zone and a large associated gas cap. However, flood response from nearby producers as a result of the barrier placement was encouraging enough to extend the use of polymers to the central area of the oil zone, where early water breakthrough had been experienced. Early results from these attempts at using polymers to improve waterflood recovery were favorable. Ultimately a total of 313,000 lb of polymer was injected into 10 of the 15 unit injectors. Polymer injection into the Northeast Hallsville Crane unit generally has been both technically and economically successful. Certainly, the effectiveness of the reservoir barrier has been well established. As for improvement of oil recoveries by mobility control, it was found that higher polymer amounts resulted in higher oil recoveries over the range of polymer treatments used. Substantially better results were achieved in areas where there was no water injection prior to the polymer slug injection. prior to the polymer slug injection. Development History

The Northeast Hallsville Crane unit is about 3 miles northwest of the town of Marshall in Harrison County, Tex. Unit production is from the Crane zone of the middle Pettit formation, a thin oolitic limestone pay at a depth of about 6,900 ft. The map in Fig. 1 pay at a depth of about 6,900 ft. The map in Fig. 1 shows the location and areal extent of the Crane porosity development and its relation to the large porosity development and its relation to the large associated Woodlawn gas field. The Crane pay in this area was first discovered in 1950 as a gas producing reservoir in the Woodlawn portion of the field. Oil production was established portion of the field. Oil production was established in the Northeast Hallsville field in 1956 as the reservoir was developed to the west. Reservoir lists had been essentially defined by early 1960 after 42 wells had been drilled. Primary oil production peaked in March, 1959, at 42,500 bbl/month. Early withdrawals from the gas zone had caused migration of oil into the gas cap by the time of the oil zone development. As a result, the gas-oil contact was not found as a clearly defined structural level but was established as a broad transition zone between approximately 6,300 and 6,400 ft subsea. The extreme volatility of the crude oil also contributed to the lack of a clearly defined gas-oil contact.

JPT

P. 1130
Development and Application of a Knowledge-Based Expert System for Cement Slurry Design
Authors: Kulakofsky D. S. , Wu F-L. , Onan D. D. , Wohleb J. B.
Published: December 2007

Traditionally, quality oilfield cement slurries have been based on rules of thumb and years of experience. The designs used in specific areas often were developed many years ago. Although these slurries may have used the best technology available when they were designed, these designs often can be improved with newer technology and products. A knowledge-based expert system can provide information regarding the latest products and technology, as well as the knowledge necessary to use them properly. This paper discusses the expert slurry-design system (ESDS) and the various considerations involved in developing a useful and usable expert system. This discussion covers establishing system goals and requirements, developing the knowledge base, creating the user interface, operating the system, and confirming ESDS results.
OILWAT - Microcomputer Program for Oil Material Balance With Gas Cap and Water Influx
Authors: Wang Ben , Litvak B. L. , Bowman G. W.
Published: December 2007

This paper describes an interactive computer program, OILWAT, for material-balance calculations in oil reservoirs with gas cap and water influx. A material-balance calculation uses production and pressure data to calculate original oil in place (OOIP) and aquifer characteristics. This formulation can be very useful in a history match to define reservoir and aquifer parameters before a simulation study. It also can be used to predict future pressure and primary production.

The use of different material-balance methods usually results in different OOIP estimates. OILWAT helps solve this problem by combining several material-balance methods with various aquifer options (small pot, steady state, and unsteady state) and comparing them statistically. Panel input and graphical output are available in the program.

Several important features are (1) variable bubblepoint, which enables very good history match during repressuring of the depleted reservoirs; (2) variable rock compressibility for abnormally pressured reservoirs; (3) an option to calculate original gas-cap or aquifer size provided that OOIP is known; and (4) applicability to saturated and/or undersaturated reservoirs. In contrast to most material-balance programs, OILWAT permits the use of a single data set for a reservoir initially at undersaturated condition that subsequently drops below bubblepoint.
A Multiplatform Reservoir Engineering Support System
Authors: Middlebrooks C. H. , Stephenson R. E. , Beard S. L. , Cummings D. L. , Hill R. L. , Natowsky P. F. , Burstall F. C.
Published: December 2007

The UNIX Reservoir Engineering Support System (RESS) is a system of networked computer applications delivering cost-effective access to state-of-the-art technology for reservoir evaluation and forecasting. This reservoir simulation support system is a set of tools to enhance engineering productivity for efficiently managing the exploitation of oil and gas reserves. RESS provides a dynamic environment in which multiple reservoir engineering tasks, such as data preparation, reservoir model submission with subsequent monitoring, and graphics, can be processed and displayed simultaneously. RESS integrates applications with complex interfaces over UNIX networks with X Window client/server architecture. The powerful multiplatform computing environment includes tools for various reservoir engineering applications residing on various platforms and the accessibility to all of it from the computing platforms on engineers' desks.
Quality Improvement: What Does It Mean in an Exploration and Production Environment?
Authors: Erickson Ron
Published: December 2007

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

The implementation of quality improvement in E&P is a fairly new idea. Many questions exist about how quality improvement can work in E&P. This paper addresses some of the most fundamental quality improvement issues. What is quality in E&P? How can quality be measured in E&P? How can quality be improved in E&P? What are the benefits of quality improvement?

Introduction

In the mid-1970's, great underlying changes, like shifting tectonic plates, began to occur in world economics. At first, they were unnoticed by most industries. But slowly and steadily, the U.S. began to lose its previously unmatched, unchallenged, and unquestioned leadership to a country that was in postwar ruin 30 years before. As a new economic age emerged, quality became a key business strategy-one that Japanese companies have used to dominate many industries.

Without a foundation built on total quality, industries were vulnerable. Within a few short years, economic quakes damaged several U.S. industries, and others vanished.

Ironically, during the 1970's and 1980's, quality actually increased in many U.S. industries. But advances in U.S. product quality could not keep up with international quality improvement. U.S. quality improved at an evolutionary rate, while Japanese quality improved at a revolutionary rate. As U.S. consumers experienced higher quality in non-U.S. products, their expectations and requirements rose faster than U.S. companies could adapt.

How Did It Happen?

The story begins 100 years ago. In the early 1900's, a scientist at Bell Laboratories noticed that successful scientists follow a general pattern to improve scientific knowledge with new ideas. First, they plan a way to test their ideas through experimentation. Second, they do their experiments. Third, they check the measured results against the planned results. Fourth, they act on the results. If their ideas are not verified, or not verified completely, they start over by modifying their ideas. But, if their ideas are validated, these ideas become standardized and are added to the body of scientific knowledge. Then, successful scientists start the process over with other ideas. The scientist who described this plan/do/check/act process of continuous experimentation was Walter Shewhart.
Applying Fractional-Flow Theory to Foams for Diversion in Matrix Acidization
Authors: Zhou Z. H. , Rossen W. R.
Published: December 2007

Fractional-flow analysis based on foam-coreflood data and the "limiting-capillary-pressure" model presents a simple, approximate way to predict diversion in foam matrix acidization. Preliminary results show that the greatest diversion is obtained when foam is preceded by a surfactant preflush and is followed by an acid slug compatible with foam.
Advances in Computer-Aided Well Test Interpretation
Authors: Horne R.N.
Published: December 2007

Several different computer methods combine to constitute a computer-aided well-test interpretation. This paper compares some of the different approaches currently in use. Future directions are discussed, as are deconvolution, pressure derivatives, model recognition, nonlinear regression, and confidence intervals.

Introduction

Despite the feeling expressed several times over the past 40 years that well-test analysis had reached its peak development, an examination of recent advances shows continuous expansion in capability, with future improvement likely. The expansion in interpretation capability over the past decade arose mainly from the development of computer-aided techniques, which, although introduced 20 years ago, have come into use only recently. The broad application of computer-aided interpretation originated with the improvement of the methodologies and continued with the expansion in computer access and capability that accompanied the explosive development of the microcomputer industry.

This paper focuses on the different pieces of the methodology that combine to constitute a computer-aided interpretation and attempts to compare some of the approaches currently used. Future directions of the approach are also discussed. The separate areas discussed are deconvolution, pressure derivatives, model recognition, nonlinear regression, and confidence intervals.

Background

During the 1970's and 1980's, mathematical and numerical techniques provided new well-test solutions for a wide variety of reservoir configurations, such as fractures, layered reservoirs, and multiple porosities. The complexity of these models and the large number of parameters that they contain limited their analysis by traditional graphical methods. Of the two main types of graphical analyses, straight-line methods (such as Horner plots) can provide estimates of, at most, two unknowns (from the slope and intercept of the line). Type-curve methods can usually provide only three parameters--one from each of the two axes and one from a curve from the family of curves used. In the process of seeking a method to match more unknowns, work began on the use of nonlinear regression. Earlougher and Kersch's 1972 paper was key in this area. That and later work showed that nonlinear regression could not only match reservoir models with more than a few parameters, but also provide several significant advantages over graphical matching. One important advantage was the illustration of the use of confidence intervals, another was the application of nonlinear regression to reservoir responses that resulted from complex (variable-rate) impulses. Matching complex models and complex impulses made up the challenge in and motivation for computer-aided analysis.
Validation of Coiled-Tubing Penetration Predictions in Horizontal Wells
Authors: van Adrichem Willem , Newman K.R.
Published: December 2007

This paper compares the predictions of a coiled-tubing tubing-forces model (TFM) with actual measured data from more than 20 wells. The model predicts the maximum depth of penetration that the coiled tubing will be able to achieve before "helical lockup" is reached and predicts the weight indicator reading as the coiled tubing is pushed through the horizontal section to lockup. The predicted penetration depth and the weight indicator readings are compared with actual values recorded during the job for open- and cased-hole completions.

Introduction

Coiled tubing is being used increasingly to service highly deviated (including horizontal) wells as the number of these wells increases. Services typically performed with either electric line or slick line in horizontal wells are often performed with coiled tubing because the coiled tubing is rigid and can be pushed into the highly deviated section of the well. Services typically performed with drillpipe or conventional tubing often are performed with coiled tubing to avoid rig costs. The services currently being run in highly deviated wells include logging, perforating, setting and retrieving plugs, opening and closing sliding sleeves, fishing, removing fill, drilling, and matrix acidizing and acid washing.

Several questions need to be answered when a coiled-tubing operation in a highly deviated well is designed. These questions include the following.How far can the coiled tubing safely penetrate and push tools into the deviated section?How can the operator ensure that the coiled tubing is being pushed into and not becoming bent in the well?How much weight can be applied with the coiled tubing to a drill bit or any other downhole tool at a point in the deviated section?

To answer these questions, a TFM was developed specifically for coiled tubing. This paper describes this model, which has been validated with measured data from jobs performed in highly deviated wells.
History Matching of a North Sea Flowline Startup
Authors: Burke N.E. , Kashou S.F. , Hawker P.C.
Published: December 2007

This paper presents a history match of the startup conditions measured for a buried offshore North Sea oil flowline. Wellhead and platform-arrival temperatures, pressures, and flow rates were predicted as the production rate varied during startup. The simulation study was performed with the new workstation version of OLGA® (Version 1.4), a transient and steady-state multiphase-fluid-flow simulator. The OLGA simulator rigorously models the transient hydraulic and heat-transfer effects that occur during flowline startup. The effects of surface production devices, such as variable area chokes, were included in this study. Results from steady-state and transient runs are compared with field data. Good agreement was obtained between field and predicted values. This study also illustrates the importance of the phase behavior of the oil, fluid properties, and heat transfer on the simulation performance. Simulated steady-state results compared favorably with results predicted by PIPEPHASE®, a steady-state multiphase-flow simulator.

Introduction

There is an increasing need to develop more oil and gas fields in harsh offshore environments. The special problems associated with offshore operations pose new challenges in the design and development of economical offshore production systems. Problems specific to the offshore environment include hydrates, wax deposition, and transient slugging. In an offshore cold-water environment, the transient effects during production system startup and shutdown become more pronounced. New transient simulation tools, such as OLGA, are becoming available that aid in the design and modeling of these transient effects. OLGA also can be used to predict the slugging and depressurization behavior of the flowline system to aid in the design of topside facilities.

This study uses the OLGA transient multiphase-flow simulator to history match actual startup data from a North Sea field. The transient data matched included mass flow rate, platform temperature and pressure, and wellhead temperature and pressure. This type of data study is useful for designing treatment and prevention programs for hydrate and wax deposition in offshore flowlines.
Case History: Design, Implementation, and Results of Separator Retrofits
Authors: Broussard G.C. , Meldrum Neil , Choi M.S.
Published: December 2007

Dubai Petroleum Co. (DPC) performed two in-situ offshore separator retrofit projects during 1989-91. Significant cost savings were achieved over the alternatives of separator replacement, addition, or modification onshore. The retrofits were accomplished without production loss or compromised operating safety. DPC's experience demonstrates that in-situ offshore facility modifications can be done successfully and simultaneously with normal operations. Improved performance after the retrofits strongly supports the need for properly designed internals to realize the full potential of a separator. Although the two retrofits share a common objective, they differ significantly in design, planning, and execution. First, a three-phase separator critical for uninterrupted production was modified during a 6-day scheduled fieldwide shutdown using only "cold work." This was followed by the conversion of a two-phase, double-barrel separator to three-phase service without a field shutdown. The work took place during 6 months with the use of "hot work." The success of both field modifications was attributed to innovative engineering and careful planning.

Introduction

Production is gathered from 67 platforms offshore Dubai, through a network of subsea multiphase pipelines to the central facilities at Fateh and S.W. Fateh (Fig. 1). Gas is separated and compressed for gas lift and pipeline export. Water is removed, processed, and disposed overboard. Separated oil from the S.W. Fateh central facilities is pumped to Fateh for further stabilization, dehydration, storage, and tanker offtake in three "khazzans." Khazzans are large, openbottom, underwater storage containers that resemble inverted champagne glasses. The oil floats on top of the water within the khazzans and displaces seawater out the bottom as more oil is introduced. During the 6 or more hours that the oil resides in the khazzans, its basic sediment and water (BS&W) is reduced to less than 0.5% for tanker sale.

Before 1987, all production separators in the system operated in the two-phase mode. They removed the gas from the produced fluid before it was sent to the khazzans. Oil and water separation took place entirely in the khazzans. This method of water separation and disposal was abandoned for three-phase separation when water production increased to levels that exceeded the capacity of the khazzans.
Description and Analysis of Cored Hydraulic Fractures—Lost Hills Field, Kern County, California
Authors: Fast R. E. , Murer A. S. , Timmer R. S.
Published: December 2007

An inclined observation well was drilled in shallow (2,000 ft) Opal-A diatomite. Seven sand-propped hydraulic fractures were cored and recovered. The hydraulic fractures were found within 5° of the azimuth measured with tiltmeters and were tilted 15° from vertical, oriented perpendicular to the formation bedding dip. Hydraulic fracture widths ranged from less than one sand grain (40/60 mesh) to 0.4 in. Scanning electron microscopy (SEM) examination of fracture faces showed no damage to the matrix from proppant embedment or compaction, and no evidence of guar residue was detected in the proppant pack or on the formation face. Fractures appear to be considerably longer than modeled. Three closely spaced fractures are interpreted to be branches of a single hydraulic fracture treatment. This paper presents a description of the fractures recovered during coring in Well OO2. Findings related to fracture dimensions and orientations, fracture sources, fracture permeability measurements, and fracture characteristics (proppant embedment, presence of gel residue) are presented. Implications related to field development are discussed.
Fracture-Liquid Transmissibility in Fractured Porous Media
Authors: Firoozabadi Abbas , Markeset Tore
Published: December 2007

The flow of oil phase in the gas/oil two-phase region in fractures is a key to production performance of fractured petroleum reservoirs where gravity drainage is the dominant mechanism. In this study, data on a set of experiments that center on flow of the oil phase in the fractures are presented. The experiments cover fracture apertures ranging from 50 to 1,200 µm, and the contact area is varied by a factor of 16. The data reveal that the rate of oil drainage across a stack of matrix blocks is very sensitive to fracture aperture size.
Borehole Stability in Shales
Authors: Bol G. M. , Wong S-W. , Davidson C. J. , Woodland D. C.
Published: December 2007

Downhole mud/shale interaction can only be properly understood if rock mechanical, shale hydration, and fluid transport phenomena are taken into account. This paper presents a review of Koninklijke Shell E&P Laboratorium's research on borehole stability in shales. Mechanisms relevant to shale stability, including pore pressure penetration (the gradual increase in pore pressure resulting from high mud weight), capillary threshold pressures, compressive and tensile failure, postfailure stabilization, hydration stress, inhibition, and osmotic phenomena are discussed. We attempt to integrate these mechanisms into a comprehensive model for shale behavior.
Calculation of Voidage for Water Injection Fillup Requirements in a Reservoir Without Initial Gas Cap When Past Production Data Are Available
Authors: Earlougher R.C. , Turner W.J.
Published: December 2007

Data required:Symbol Cumulative oil production, STB Np

Cumulative gas production, Mcf Gp

Cumulative water production, bbl Wp

Original formation volume factor Boi

Formation volume factor at zeroreservoir pressure and atreservoir temperature Boa

Original solution GOR Rsi

Cumulative water injection, bbl Wi

Desired:

Gross liquid voidage from the reservoir, in barrels, resulting from production of oil, gas, and water. This value represents the volume of net waterinjection required to fill the reservoir with liquidand thus regain initial bottom-hole pressure. Whenthat condition has been fulfilled, "fillup" will havebeen attained.

Vt = cumulative gross voidage, bbl

Vtn = cumulative net voidage, bbl

Vt = current gross voidage, B/D

Vtn = current net voidage, B/D

Fillup = Vt at start of water injection

Solution:

Vt =

Vtn =

Vt =

where

Vt2 = cumulative gross voidage at end ofmonth,

Vt1 = cumulative voidage at end of previousmonth, and

d = days in the month.

Vt =

This calculation assumes that all free gas in the reservoir will go back into solution as reservoir pressure is increased by injection. Field performance pressure is increased by injection. Field performance of waterfloods confirms this assumption. Average reservoir pressure will increase relatively slowly up to 50 to 80 percent of fillup and then build up rapidly.

P. 931
Annular Re-injection of Drilling Wastes
Authors: Minton R.C. , Secoy Byron
Published: December 2007

Annular reinjection offers a cost-effective disposal mechanism for the oily cuttings and associated wastes generated when oil-based muds are used during drilling. This disposal method eliminates overboard cuttings discharge and hence removes any environmental impact. Continued use of oil-based muds is therefore feasible. A 12-member Drilling Engineering Assn. in Europe (DEAE) project was initiated in 1990 to study the engineering aspects of this approach in the North Sea. This paper reports on the first trial off a fixed platform in the North Sea and discusses the preliminary engineering studies, injection, and analysis of fracture propagation. It demonstrates that, with proper regard to the engineering of the injection well, the process is a safe, efficient, and effective disposal technique.

Introduction

Low-toxicity oil-based muds (LTOBM's), used widely in the North Sea operating area, offer significant operational benefits, especially for exploration and appraisal drilling and, more importantly, for development drilling. However, the overboard discharge of the oil-contaminated cuttings leads to environmental damage that, although localized, is unacceptable.

To resolve this conundrum, novel water-based muds were evaluated and a range of cleaning and disposal options for the cuttings was reviewed. From these options, cuttings slurrying and reinjection appeared to offer the most cost-effective solution because this approach would also address the problem of oily liquids from the drilling unit. Cuttings slurrying and reinjection is established practice in Alaska and the Gulf of Mexico, but the technique had not been used previously in the North Sea.

We knew that the legislative authorities would have some concerns. Therefore, 12 operating companies sponsored a joint project, through the auspices of the DEAE, to evaluate the engineering issues associated with this approach. The project was established with three objectives in mind:to demonstrate that cuttings slurrying and reinjection was technically viable for the North Sea,to gain acceptance of this approach to waste management from North Sea legislative authorities, andto evaluate a novel approach to cuttings grinding.
A Transform Approach to the Simulation of Transient Gas Flow in Porous Media
Authors: Andre H. , Bennion D.W.
Published: December 2007

The mathematical description of transient gas flow through porous media leads to a second-order nonlinear partial differential equation for which no analytical solution bas been found. For flow in one linear dimension, this paper outlines a procedure for using finite Fourier transforms to reduce the partial differential equations to a set of first-order, partial differential equations to a set of first-order, nonlinear ordinary differential equations with time as the independent variable. The dependent variables of these equations are the Fourier transform coefficients of the gas pressure in the porous media The procedure is applied to an porous media The procedure is applied to an example problem and calculated results are compared with other published results obtained by a numerical finite-difference technique. The good agreement shown between the two sets of results tends to confirm the validity of both solutions.

Introduction

The differential equation describing one-dimensional gas flow in porous media is a nonlinear equation with no known analytical solution. Numerical finite-difference methods are normally used to solve the flow equation. This paper presents a method which uses linear analysis to transform a second-order problem into a set of first-order problems. Basically the approach used is to assume an approximation of the solution consisting of known functions and unknown parameters and apply some error distribution parameters and apply some error distribution principles to determine the parameters of the principles to determine the parameters of the approximation. Although there are several error distribution principles, one of the most common is the orthogonal method. Recently special cases of the orthogonal method, the Galerkin or Bubnov-Galerkin have been applied by Price et al., to petroleum reservoir problems with considerable success. A classical orthogonal method is finite Fourier transforms. Recently several authors have demonstrated that this method can be used with considerable success in the simulation of systems described by a limited class of linear partial differential equations. This paper is intended to demonstrate that the finite Fourier transform method can be used to reduce the nonlinear partial differential equation describing gas flow in a linear porous media to a set of ordinary differential equations.

THEORY

The basic equation being studied is:

............(1)

which is derived from the continuity equation

...............(2)

the equation of state

..............(3)

and Darcy's law

................(4)

For the orthogonal method of error distribution, the procedure is to assume an approximate solution Pa, define an error L[pa] and require that this error Pa, define an error L[pa] and require that this error be orthogonal to N independent functions n(x) (n=1,2.... N)

...................(5)

SPEJ

P. 135
Relation Between Chemistry and Flow Mechanics of Borate-Crosslinked Fracturing Fluids
Authors: Kruijf de A. S. , Roodhart L. P. , Davies D. R.
Published: December 2007

Borate-crosslinked guar or hydroxypropyl guar (HPG) polymer solutions have become increasingly popular as hydraulic fracturing fluids. These fluids are cheap and environmentally friendly, and they minimally impair a propped fracture while yielding maximum viscosity. The drawbacks, which have limited their use, are a restricted temperature range of applicability, relatively high tubing friction, and poor stability when prepared with seawater. This paper shows how these drawbacks can be eliminated by a fundamental understanding of the relation between fluid chemistry (as a function of borate crosslinker, pH, and polymer/crosslinker concentration) and its physical properties (proppant-carrying capacity, viscoelasticity, and the temperature stability of the resulting crosslinked structure).
Interaction of Viscous Fingering, Permeability Heterogeneity, and Gravity Segregation in Three Dimensions
Authors: Tchelepi H. A. , Orr F. M.
Published: December 2007

Two- and three-dimensional computations with a hybrid finite-difference/particle-tracking technique are compared for unstable displacements. In both homogeneous and heterogeneous porous media, gravity segregation is much more effective in 3D than in 2D computations. Whether flow is 2D or 3D, the presence of correlated heterogeneities lowers the range of viscous/gravity ratio over which the transition from gravity- to fingering-dominated flow occurs.
Comparison of 2D and 3D Fractal Distributions in Reservoir Simulations
Authors: Beier R. A. , Hardy H. H.
Published: December 2007

Fractal geostatistics can be used to generate distributions of such reservoir properties as porosity and permeability. We compare three different methods that use these distributions in reservoir simulations. The first method is a hybrid finite-difference/stream-tube method that starts with 2D vertical cross sections with relatively fine grids, the second uses pseudo-relative permeabilities and also is based on 2D cross sections, and the third uses 3D distributions. A mature waterflood in a carbonate reservoir serves as a field test case.
Effect of Phase Behavior on Bypassing in Enriched Gasfloods
Authors: Burger J. E. , Bhogeswara Rao , Mohanty K. K.
Published: December 2007

Enriched gasfloods incorporate a complex interaction of heterogeneity, fingering, multiphase flow, and phase behavior. Experiments and simulations indicate that the optimum solvent enrichment in high-viscosity-ratio secondary gasfloods can be below minimum miscibility enrichment (MME). The compositional path and resulting mobility profile in multidimensional multiple-contact miscible (MCM) or immiscible floods are different from their ID counterparts for high-viscosity-ratio floods in heterogeneous media.
The Impact of Wettability on Waterflooding: Pore-Scale Simulation
Authors: McDougall S. R. , Sorbie K. S.
Published: December 2007

This paper describes the development and implementation of a pore-scale simulator into which pore-wettability effects have been incorporated. Relative permeability and capillary pressure curves from this steady-state model have been analyzed to allow better interpretation of experimental observations from a microscopic standpoint. The simulated capillary pressure data demonstrate that some standard wettability tests (such as Amott-Harvey and free imbibition) may give misleading results when the sample is fractionally wet in nature. Waterflood displacement efficiencies for a range of wettability conditions have been calculated, and recovery is shown to be maximum when the oil-wet pore fraction approaches 0.5. Furthermore, a novel experimental test is proposed that can be used to distinguish between fractionally wet and mixed-wet porous media. To date, no such satisfactory test exists.