bluuebunny/crossref_metadata_2025 huggingface dataset:
Potential for Infill Drilling in a Naturally Fractured Tight Gas Sandstone Reservoir
Authors: Harstad H. , Teufel L.W. , Lorenz J.C.
Published: December 2007

Modeling of the Mesaverde Formation in the San Juan Basin, northwestern New Mexico, shows the importance of using realistic drainage patterns in a naturally fractured reservoir. Fractures not only enhance the overall porosity and permeability of these reservoirs, but fractures also create significant permeability anisotropy. Permeability anisotropy causes the drainage area around the wells to be elliptical. Directional permeability is best found with multiple well interference tests. Predicted potential for infill drilling depends on the modeling approach, because elliptical drainage creates more overlap and undrained sections than a more radial drainage in an isotropic permeability case. Modeling with permeability anisotropy increases the potential for infill drilling and identifies optimum locations for new infill wells.

This approach has been applied in the Mesaverde Formation to determine economic optimization of infill drilling in these reservoirs and demonstrates that field development based on elliptical drainage areas can lead to a reduction in drainage overlap of adjacent wells and prevent leaving undrained areas. From multiple well interference testing a strong permeability an isotropy was found. Reservoir simulations were performed in pilot areas of different fracture intensity to quantify the potential for infill drilling, reducing the well spacing from 320 to 160 acre. Simulation results indicate areas of effective drainage, the optimum locations for infill wells, and the additional recovery from infill wells.

P. 59
Optimizing Well Capacity in a Tight Carboniferous Reservoir
Authors: Luan G. , Steffan E.M. , Weber R.
Published: December 2007

The Husum/Schneeren gas field, situated to the Northwest of Hannover, Germany, was discovered in 1986 and is jointly operated by BEB Erdgas & Erdol GmbH and Preussag Energie GmbH. The field was put on stream in 1987 when economic production was proven with the well Husum Zl, and reached plateau production in 1994 with 6 wells completing the initial development (Husum Z1 and Z2, Schneeren-Ost Z1, Schneeren Z 1/ Z2, Schneeren-West Zl).

Husum/Schneeren is a wrench related pop-up structure, with a gas column of about 1 000 m (3 300 ft), located at a depth of 2 300 m TVSS (7 550 ft) beneath the Husum salt dome. The reservoir comprises tight Westfalian fluviatile sandstones with average porosities of 5 %, mean permeabilities of 10 D, and an initial reservoir pressure of 385 bar (5 500 psi). The productivity of the reservoir is due to the presence of natural fracture systems which relate to the position of the structure at the intersection of two major tectonic lineaments. During drilling operations mud losses occurred due to high overbalance at the top of the large gas column. In all the early wells, therefore, a cemented liner was set over the reservoir interval and perforated in the fractured zones. Due to the unpredictability of the contribution of individual fractures to the production, initial well capacity was limited to 10 000 m3Ih (8.5 Mscf/d). Only after additional perforations could the current capacity level of 30 000 m3Ih (25 Mscf/d) at WHFP of 140 bar (2000 psi) be reached.

For a recent development well (Husum Z3), the reservoir target was chosen along the northern, highly fractured flank of the structure. In order to reach a borehole length of at least 800 m (2 800 ft) without experiencing severe mud losses, the well was drilled slanted at 450 through the slightly depleted reservoir, and completed open hole with a predrilled liner. Well capacity was tested at 30 000 m3lh (25 Mscf/d) at a WHFP of 200 bar (2 900 psi), enabling this unconventional tight reservoir to be drained efficiently.

P. 83
Surface Tiltmeter Fracture Mapping Reaches New Depths - 10,000 Feet and Beyond?
Authors: Wright C.A. , Davis E.J. , Minner W.A. , Ward J.F. , Weijers L. , Schell E.J. , Hunter S.P.
Published: December 2007

Recent improvements in tilt measurement techniques have greatly enhanced the resolution of hydraulic fracture-induced tilts, resulting in both greater mapping precision and an increase in the maximum mapping depth achievable with a surface tiltmeter array. With a previous depth limitation of around 6,000 ft., surface tiltmeter mapping was limited to areas with relatively shallow production. Application is greatly broadened now with a depth range down to 10,000 ft. In addition to the expanded depth range, there has been a marked improvement in the fracture mapping resolution.

This paper begins with an overview of the tiltmeter fracture mapping concept, highlighting both the strengths of this technique and its limitations. Following that is a description of the technical advancements made over the last three years to allow fracture mapping at far greater depths. Finally, two brief case studies are presented to demonstrate fracture mapping at great depth, and also to provide insight on hydraulic fracture growth behavior in two different environments. As the case studies make clear, fracture growth is far more complex than is generally assumed. Better understanding of these complexities can lead to significantly enhanced fracture stimulation practices.

P. 135
Development of the Pekisko Dolomite in the Bigoray Field. Issues in Formation Damage Mechanisms, Drilling Fluid Selection and Well Stimulation
Authors: Warren Brent K. , Skea Ken , Johnson Stan , Smithinsky Steve , Lunan Brian
Published: December 2007

The Pekisko formation in the Bigoray field in central Alberta is an oil-bearing dual permeability/porosity dolomite. A portion of the reservoir has permeabilities in the range of 1-2 Darcy and porosities approaching 25-30% while the rest of the reservoir features 10-30 millidarcy average permeabilities, 8-12% porosities and low initial water saturation. It is suspected that both rock types contribute to the flow of oil.

Drilling of horizontal wells in the Pekisko formation offers technological challenges in terms of field development and formation impairment. Damage mechanisms for the two rock types are expected to be different yet need to be addressed in one drilling fluid system. Open hole completion/stimulation to repair any formation damage and the avoidance of underlying water adds to the drilling challenges.

This paper describes the results of laboratory formation damage studies to both identify damage mechanisms and evaluate which drilling fluid system to be used in the horizontal well section. The higher permeability/porosity dolomite core plugs were damaged by solids plugging while aqueous phase trapping and solids plugging were responsible for damage in the lower quality rock.

A total of eight horizontal wells have been drilled in the field as of December 1997. The horizontal wells were drilled with three types of drilling fluids: oil, oil-soluble resin and a carbonate bridging system containing an aqueous phase trap reduction agent. The horizontal wells drilled with the carbonate/aqueous phase trap drilling fluid system had better oil production and less water than the wells drilled with the other drilling fluids. Discussion will also focus on stimulation of those horizontal wells that were damaged in the drilling process.

P. 161
Reservoir and Completion Study Improves Results in the Deep Red Fork Formation
Authors: Burns R.A. , Poulson T.D. , Finch R.W. , Aud W.W.
Published: December 2007

Technical integration of past stimulation practices with the subsequent production responses provided the insight for optimizing completion and stimulation practices in the deep Red Fork play of the Southwest Canyon City field. This case history illustrates the methods used to characterize the reservoir properties and the effectiveness of prior completion approaches. Based on these evaluations, a customized completion and stimulation approach was developed that was specifically tailored to match the identified reservoir, producing, and fracturing characteristics. Coupled with real-time execution of fracture stimulation treatments, this optimized approach increased the average daily production by 71% while reducing completion costs approximately ﹩150,000 per well. Average cumulative production from the 5 wells after 300 days using the new approach has increased from 400 MMscf to 700 MMscf. This combination of increased production and lower completion costs has dramatically improved the economic return from the field.

P. 185
Underbalanced Drilling in the Williston Basin
Authors: Purvis D. L. , Smith D. D.
Published: December 2007

The value of underbalanced drilling of open hole completed wellbores to minimize formation damage has been well established.

Underbalanced drilling by design does not build a filter cake in the wellbore. During conventional drilling this filter cake acts as a protective barrier reducing damage to formation permeability from drill cuttings. When drilling extended reach horizontal wellbores drill cuttings are ground into fine powder by the rotating drillpipe. If the wellbore does not have a filter cake and becomes overbalanced, this powder is carried into the formation greatly reducing near wellbore permeability. For this reason, preplanning and on-site engineering are critical in maintaining an underbalanced condition. Coordination and communication between drilling, nitrogen injection and return fluid handling are critical. This paper outlines the steps required from initial preplanning through the completion of the horizontal section. Case histories and results are presented. Various techniques for achieving an underbalanced condition via gas injection are examined. Nitrogen injection via a parasite string is examined in detail. Pre-planning steps are presented along with potential pitfalls and how to avoid them. A computer model capable of calculating the downhole pressure and flow conditions while drilling is described. The effect on pressure resulting from changes in injection rate, gas rate, density, viscosity and return pressure is analyzed. A comparison of modeled vs. actual downhole pressures is made to verify the validity of the model.
Decline Analysis' Relationship to Relative Permeability in Secondary and Tertiary recover
Authors: Masoner L.O.
Published: December 2007

Oil production declines under two processes:

pressure depletion and decreasing oil relative permeability as the oil saturation declines.

The literature offers derivations of Arps' exponential and hyperbolic decline equations for pressure depletion decline; these derivations apply to single phase flow or solution gas drive recovery only. This paper proceeds to derive Arps' hyperbolic decline equation from the principles of relative permeability. The results indicate that hyperbolic decline rigorously applies for relative permeability dominated secondary and tertiary oil recovery processes. Arps' exponential and harmonic declines apply only under very special conditions. The results further emphasize that history matched decline constants apply only during the recovery process under which they were determined. A method of translating between field scale oil relative permeability curves and oil decline is provided. The physical basis for the decline exponent, b, for these processes is revealed along with expected value ranges.

P. 245
Multiple Trend Forecasting Accounts for field Constraints
Authors: Wilson Scott J. , Miller Mark R. , Frazer Lamont C. , Digert Scott A.
Published: December 2007

Traditional decline curve analysis relies on curve fitting the primary producing phase while assuming that the other producing streams need not be considered. Both the Arps and Modem decline models consider only one producing stream when forecasting future rates. Although single phase trending is appropriate in many cases, incorporating the other streams improves the overall forecast reliability, especially where field liquid gas-handling constraints are significant drivers in a well's production profile.

This paper documents the practice of mathematically combining multiple production trends to improve predictions of the future performance of the single primary phase. Two methods are described in detail which specifically account for mature waterflood performance and gas-handling constrained production. Several field examples show the improved forecasts available from these relatively simple models. Although these methods are slightly more complex than single-phase curve fitting, modern computer decline programs are easily capable of implementing the models described here.

P. 253
An Integrated Method for Optimizing Hydraulic Fracture Design for Tight Gas Wells
Authors: Rietman Noel D.
Published: December 2007

A fully integrated method for optimizing frac treatments for tight gas wells has been devised. It includes predicting the flow performance under three flow regimes, matching well performance to determine or confirm the kh drainage area, and achieved frac length, and calculating the optimum frac length by using derivative curves. The sensitivity of the optimum length to different variables can also be determined easily by this method. For the reservoir and cost conditions considered, the optimum frac length is the most sensitive to variations in porosity, frac cost and pay thickness, somewhat less sensitive to drainage area, initial pressure and water saturation, and much less sensitive to permeability.

P. 259
Applications of Pre-Frac Injection/Falloff Tests in fissured Reservoirs - Field Examples
Authors: Barree R.D.
Published: December 2007

A method has been developed, based on the pressure versus 6-function curve and its derivatives, to characterize the pressure dependent behavior of formations from injection fall off test data. Characteristic shapes of the derivative curves differentiate between various closure mechanisms including pressure dependent leakoff associated with fissure opening. The dominant closure mechanism has been found to influence the treating behavior of the formation and help define the optimum fracture treatment design for the interval. In this paper, field examples of each major type of closure mechanism are presented along with the fracture treating response observed. The impact of natural fractures on production and injection will also be discussed.

Introduction

This paper is an extension of work originally presented at the SPE Annual Conference and Exhibition in 1996. The previous paper described the expected pressure falloff response of the 6-function and its derivatives, for pressure dependent leakoff and other factors affecting rate of fracture closure. The derivative response was predicted using the GOHFER fracture design simulator. This work adds to our understanding of pressure falloff behavior through the acquisition and analysis of extensive field data examples.

In the pioneering work by Nolte in 1979, fracture pressure decline analysis was proposed as a key to successful fracture stimulation treatment design. The method proposed was to inject a small fluid volume at constant rate and analyze the pressure decline to determine the fluid efficiency and pad volume requirement for achieving the desired fracture length. This technology appeared to offer a key to improved stimulation design.

By 1985 it was realized that this method, while very successful in many instances, did not generally identity wells which would be very difficult to hydraulically fracture. Many screenouts occurred which were not predicted by the existing pressure falloff analysis techniques. One possible cause of the noted failures was suspected to be pressure dependent leakoft, or fluid loss which increases with treating pressure.
Single and Multi-Well Modeling of a Tight Gas Sand in the Denver-Julesburg Basin, Colorado
Authors: Boone Lynn E. , Moore H. David , Birmingham Thomas J. , Delaney Jeffery C.
Published: December 2007

Fully-compositional, dual-porosity simulation models were constructed for the Codell Sandstone of the Wattenberg field in the Denver-Julesburg Basin, Colorado. The objective of this work was to develop simulation models which could accurately forecast reservoir behavior under various development scenarios. Characterization of the Codell formation is difficult due to heterogeneities in depositional and diagenetic fabric. Discontinuous higher-permeability layers, dispersed within a compact low-permeability matrix of the reservoir, requires connection to the wellbore through hydraulically induced fractures. Initially, a singe-well model was constructed to study the reservoir flow behavior in detail.

This model was used to develop a dual-porosity characterization representative of the reservoir within the drainage area of an individual well. The results of these simulations were then incorporated in a multi-well model used to investigate various development scenarios for several areas of the field. The reservoir descriptions in these models were derived from available log, core, PVT, and well test data. A fully-compositional fluid description was used to facilitate representation of significant changes in fluid properties across the field. Faults potentially affecting flow within the reservoir were identified during detailed geologic mapping.

P. 289
The Triangle "U" Sussex Unit - A Chemical Flood Case History
Authors: Smith J.E. , Larsen Dan
Published: December 2007

The Triangle "U" Unit is located in Campbell County, Wyoming, in the Powder River Basin. The field produces mainly from the Sussex "A" Sandstone, with completions and limited production from the Sussex "B". The flood recovered 12.8% OOIP on primary prior to the waterflood, which commenced in March, 1981. The Sussex "A" is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays and the initial injection water source was fresh, leading to concerns about long-term injectivity.

To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long- term performance of the two groups of injection wells shows that the wells treated with KOH injected 556,000 BBLS/porosity-foot more water than the wells treated with cationic polymer, in 1.4 years less time. Following KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March, 1997, is 36.4% OOlP, compared to the original waterflood projection of 26.6% OOlP. A total of 37.7% PV water has been injected, and the water-oil-ratio is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone.

P. 307
A Case History: Completion and Stimulation of Horizontal Wells with Multiple Transverse Hydraulic Fractures in the Lost Hills Diatomite
Authors: Emanuele M.A. , Minner W.A. , Weijers L. , Broussard E.J. , Blevens D.M. , Taylor B.T.
Published: December 2007

The Lost Hills Field Diatomite has traditionally been developed using vertical wells completed with multiple propped hydraulic fracture treatment stages. As the main portion of the field is nearing full development at 2 1/2-acres per producer, the search for additional reserves has moved out to the flanks of the field's anticlinal structure. Due to limited pay thickness, these flank portions of the field will not support economic vertical well development. The use of horizontal wells was determined to have the best chance to economically develop these areas of the field. To evaluate this development concept, three horizontal wells were drilled and completed over the time period from November 1996 to December 1997

To assist with the horizontal well design and evaluation, several vertical data wells were drilled offset and parallel to the intended well path of each horizontal well. Additionally, two vertical core wells were drilled in line with the toe and heel of the horizontal well paths. These data wells were utilized to estimate properties such as in-situ stress profiles, pore pressure gradients, rock properties and fluid saturations, and to determine horizontal well vertical depth placement. The horizontal wells were then drilled in the direction of minimum horizontal stress (transverse to the preferred hydraulic fracture orientation) and completed with multiple-staged propped hydraulic fracture treatments.

During the completion of the three horizontal wells, hydraulic fracture growth behavior was characterized using surface tiltmeter fracture mapping and real-time fracture pressure analysis. In the third horizontal well, downhole tiltmeter fracture mapping was also used. This combination of fracture diagnostics provided significant insights into hydraulic fracture behavior, allowing diagnosis of anomalous fracture growth behavior and evaluation of remediation measures. Fracture diagnostics during the first horizontal well revealed an unexpectedly complex near-wellbore fracture geometry, a result of fracture initiation problems. These problems slowed the completion process and severely harmed the effectiveness of the fracture-to-wellbore connection. In the subsequent horizontal wells, a number of design and execution changes were made which resulted in simpler near-wellbore fracture geometry and a greatly improved production response.

The paper provides an overview of the completion and stimulation of all three horizontal wells, describes the lessons learned along the way, and discusses the implications for future Lost Hills horizontal well development.

P. 335
Horizontal Drilling Success in the East Painter Field of Southwest Wyoming
Authors: Weatherl M.H.
Published: December 2007

Horizontal technology was first utilized in the East Painter Field during the summer of 1996 through the drilling of the EPRU 41 - 1 8AH well. This was the first application of horizontal technology in the Nugget formation in the Rocky Mountains in recent years. The only other effort occurred in 1988 and has been previously described (1). Substantial success was achieved and several breakthroughs occurred with regard to drilling and completion philosophy for this type of well. This paper describes the background, planning, drilling, and completion sequence for EPRU 41-1 8AH. A review of more recent horizontal drilling efforts in the Field is provided as well.

P. 349
Induced Stress Diversion: A Novel Approach to Fracturing Multiple Pay Sands of the NBU Field, Uintah Co., Utah
Authors: Hewett T.W. , Spence C.J.
Published: December 2007

This paper presents results of utilizing "Induced Stress Diversion" (ISD) to fracture stimulate multiple pay sands in the Natural Buttes Field of Uintah County, Utah. Historically, these multiple pay sands have been stimulated with the Limited Entry technique. To a lesser degree, some wells have been stimulated in stages using positive isolation. The decision to try "Induced Stress Diversion" (ISD) was made to combine the economies of the limited entry technique with the superior production results expected of a staged completion. The technique involves pumping multiple flacs in a well relying on the Induced Stress imparted by the first fracture stimulation to divert the subsequent frac into the desired zone (i.e. no positive isolation).

The ISD technique has worked well in many instances to date. This is especially notable because the majority of wells thus far have been done without consistent attempts to close the fracture prior to commencing the next fracture stage. To allow the technique to have wider application, emphasis is currently directed at improved methods of inducing screenout. Based on initial results, the technique appears to have wide application and could improve the economics of developing multiple-pay reservoirs.

P. 375
Hydraulic Fracturing of the Frontier Zone in West-Central Wyoming A Case History
Authors: Lehman L.V. , Yaritz J.G. , Natvig R.
Published: December 2007

This case-history paper shows that dry-gas sandstone reservoirs in the Frontier zone in west-central Wyoming produce more gas when they are fracture-stimulated with fracturing fluids at lower pH values than conventional high-pH fracturing fluids with pH values greater than 10. Fracturing fluids at reduced pH values may be broken with oxidizing or enzyme breakers that are either encapsulated or applied in the conventional manner. Databases analyzed for this paper show that dry-gas sandstone wells stimulated with conventional high-pH borate (CHPHB) fluids produce less hydrocarbon during a comparable time frame than similar wells stimulated with zirconium-crosslinked fluids at moderate pH levels.

The merits of low-guar borate (LGB) at lowered pH values have been documented previously. This paper will introduce and discuss the benefits of using a low-polymer zirconium fracturing fluid at neutral pH values in dry-gas sandstone applications. Information and discussion are presented as follows:Retained-conductivity tests were performed using dry-gas flowback. These test practices fit results for dry-gas sandstones better than conventional conductivity testing using water as the flowback medium.The properties that make CHPHB popular in many applications may not be the optimum method to stimulate low- permeability, dry-gas sandstones. CHPHB fluids are borate gels complexed at high-pH values >10).The geochemistry of some formations may not be suitable to fracture with high-pH fluids.LPZ, a low-polymer zirconium fracturing fluid is introduced as an alternative stimulation fluid. LPZ shows better performance than CHPHB for dry-gas sandstone reservoirs.

P. 495
High-Rate Foam Fracturing
Authors: Harris Phillip C. , Pippin Mike
Published: December 2007

Foam-fracturing treatments pumped down 3.- 5-to 4.5-in. tubing at up to 80 bbl/min have presented problems in control and execution. Wellhead pressures used to predict net entry pressure can give erratic results in the absence of good knowledge of bottomhole pressure (BHP). Since nitrogen (N2) delivery rates are pressure sensitive, errors in BHP estimation cause control problems with both rate and foam quality. Perforation erosion, if unaccounted for, can signal a need for increase in rate to maintain BHP.

We used a laboratory study of foam in laminar and turbulent flow and a series of field experiments with bottomhole gauges to calibrate foam friction-pressure in tubulars at very high rates. To measure the viscosity of foam fluid with N at 1,000 psi, we used a small-scale, flow-loop viscometer that could be applied in both laminar and turbulent flow. Foam parameters included foam qualities from 25 to 80% N2 and guar concentrations from 0 to 40 lb/Mgal. The effects of surfactant concentrations from 0.2 to 1.0% were also studied.

Field foam treatments pumped at high foam rates were equipped with bottomhole real-time transmitting gauges. Step-rate tests were performed on both neat foam and sand-laden foam to calculate friction pressures. Actual friction pressures from these treatments were compared with pressures based on laboratory data. The laboratory correlation can predict tubular friction accurately for foam fluids up to very high foam rates.

In several of the treatments, small perforations were used in an attempt to provide limited entry stimulation. With the bottomhole-gauge data, we were able to assess the effects of perforation erosion because of changes in sand concentration.

Results of this study were used to support the design of lower foam frac rates. The average rate of 80 bbl/min was lowered to 40 bbl/min resulting in a fracturing cost savings of approximately ﹩7,400 per treatment. The success of these lower rates has been verified by both after-frac tracer logs and on-line production.

P. 509
Porosity and Permeability Prediction in Low-Permeability Gas Reservoirs From Well Logs Using Neura Networks
Authors: Olson Terrilyn M.
Published: December 2007

Artificial neural networks are gaining popularity as tools for estimating reservoir parameters from limited, common data suites. Requirements for their use include input data such as well logs that relate to the desired output, and "truth" data for training. Two case studies will be used to illustrate the use of neural networks to predict porosity and permeability from log data. In both cases, the predictions were needed for field studies aimed at improving reservoir management and optimizing production.

In the giant Hugoton gas field in Kansas, porosity was predicted from spectral gamma ray, photoelectric, and bulk density data with generic neural network software. Such software allowed the relationship developed by the neural network to be translated into an equation that could be readily applied to all wells with the requisite log curves. Permeability was predicted using a more log-oriented type of software, one that incorporated depth windows of input data in generating and applying the network. In addition to the input curves used for porosity, neutron logs were used in the permeability prediction. In the Hugoton example, mineralogy was a critical factor in porosity and permeability determination, so most of the input data provided information about mineral constituents of the reservoir. Core analyses served as "truth" cases in training both porosity and permeability neural networks.

In the Red Oak gas field in Oklahoma, where density logs are commonly absent or of poor quality, multiple neural networks were developed to predict density from gamma ray and deep induction data. A combination of measured and predicted density curves were then used to calculate porosity.

One additional network was built to estimate permeability from gamma ray, induction, and density data over 5 orders of magnitude of permeability, with core plug permeability measurements used as truth in training. Key features of these networks were selective rather than statistical training, back prediction of input data for validation, and the use of vertical intervals of input data.

One additional network was built to estimate permeability form gamma ray, induction, and density data over 5 orders of magnitude of permeability, with core plug permeability measurements used as truth in training. Key features of these networks were selective rather that statistical training, back prediction of input data for validation, and the use of vertical intervals of input data.

P. 563
Well Head Test Analysis: Save and Safe
Authors: Dall'Olio D. , Vignati L.
Published: December 2007

A methodology was developed which allows the use of well head pressure record for test interpretation purpose, correcting the obtained results to reservoir conditions. The methodology was validated on Italian gas fields comparing the results of the bottom-hole and well-head data analyses for depth ranging between 1000 and 4000 meters and gas rate between 50 to 1000 kSm3/d. Problems could arise when a massive two-phase flow in tubing occurs, because the well bore effects can reduce the quality of interpretation.

P. 139
Analysis of Linear Flow in Gas Well Production
Authors: El-Banbi Ahmed H. , Wattenbarger Robert A.
Published: December 2007

Linear flow may be a very important flow regime in fractured gas wells. It is also important in some unfractured wells. This paper presents practical approach to analyze both pressure (well testing) and production rate (decline curve analysis) data which is influenced by linear flow. The paper explains two approaches to analyze the date (hand calculations and curve fitting). It uses analytical solutions that are adapted to different reservoir models. These models include fractured wells and wells producing reservoirs with high permeability streaks. Permeability, flow area, and pore volume may be obtained from either pressure or production rate data. The constant rate solutions are different form the constant pressure solutions. The use of the wrong equations in the analysis may result in errors as high as 60%. The paper also shows the application of these techniques in analyzing field data.

P. 145
Drainage Efficiency in Naturally Fractured Tight Gas Sandstone Reservoirs
Authors: Harstad H. , Teufel L.W. , Lorenz J.C.
Published: December 2007

Modeling of the Mesaverde Formation in the San Juan Basin, northwestern New Mexico, shows the importance of using realistic drainage patterns in a naturally fractured reservoir. Fractures not only enhance the overall porosity and permeability of these reservoirs, but fractures also create significant permeability an isotropy. Permeability an isotropy causes the drainage area around the wells to be elliptical. Directional permeability is best found with multiple well interference tests. Predicted potential for infill drilling depends on the modeling approach, because elliptical drainage creates more overlap and undrained sections than a more radial drainage in an isotropic permeability case. Modeling with permeability anisotropy increases the potential for infill drilling and identifies optimum locations for new infill wells.

This approach has been applied in the Mesaverde Formation to determine economic optimization of infill drilling in these reservoirs and demonstrates that field development based on elliptical drainage areas can lead to a reduction in drainage overlap of adjacent wells and prevent leaving undrained areas. From multiple well interference testing a strong permeability an isotropy was found. Reservoir simulations were performed in pilot areas of different fracture intensity to quantify the potential for infill drilling, reducing the well spacing from 320 to 160 acre. Simulation results indicate areas of effective drainage, the optimum locations for infill wells, and the additional recovery from infill wells.

P. 157
Non-Darcy Measurements in Dry Core and the Effect of Immobile Liquid
Authors: Coles M.E. , Hartman K.J.
Published: December 2007

Non-Darcy flow increases the pressure drop required to establish a desired gas well production rate, thus decreasing productivity. This increased pressure drop is exacerbated by the liquid drop-out and build-up which occurs in gas condensate wells. The additional pressure drop caused by the two phase non-Darcy flow can have a dramatic effect on the flowing bottom hole pressure required to maintain producing rates, especially in high rate gas condensate systems. Neglecting or underestimating this effect will cause optimistic predictions of the maintenance of gas rate plateau.

Literature values for measured inertial coefficients, (which quantify non-Darcy flow pressure drops) show a scatter of a one to two orders magnitude for a given permeability. Measurements of inertial coefficients (betas) may or may not agree with literature reported values. Use of literature reported permeability - beta relationships to calculate beta may not be appropriate and may lead to significant errors. These errors increase with increasing flow rate and decreasing permeability.

This paper presents transient flow beta measurements obtained in dry core samples and in samples containing different saturations of immobile liquid. Results from core samples from three different reservoirs and one outcrop are included. A method has been developed to estimate the effective beta at different liquid saturations using core samples containing various saturations of solidified paraffin wax that mimic an immobile condensate phase. Continued validation of this technique will allow simplified and inexpensive beta measurements as functions of saturation and permeability

A relationship has been derived which allows the inertial coefficient to be estimated as a function of effective permeability and effective porosity. This relationship appears to hold for almost all of the core samples tested and includes both dry and saturated samples. The relationship, which includes both permeability and porosity, provides significantly reduced scatter compared with previous permeability-beta relationships and allows better understanding and estimation of beta.

P. 193
Preliminary Investigation of Coalbed Methane Potential of the Zonguldak Basin in Turkey
Authors: Serpen Umran , Alpkaya Ebru N. , Ozkan Erdal
Published: December 2007

This paper presents the results of a preliminary investigation of the coalbed methane potential of the Zonguldak Basin in Turkey. A stochastic approach is used in the investigation primarily because of the lack of sufficient data. The results clearly indicate the adequacy and the advantage of the stochastic approach over the deterministic procedures. The Monte Carlo simulation is used to obtain the probability distribution of in-situ and recoverable coalbed methane reserves in the Zonguldak Basin. An economic evaluation of a potential development project is also presented. It is shown that despite the conservative estimates of the reserves, coal bed methane production from the Zonguldak Basin is a feasible project.

P. 227
Minimizing Multiple Fractures in Coalbed Methane Fracturing Operations
Authors: Kilstrom Kevin , van Gijtenbeek Klaas , Tjoonk Richard , Palmer Ian
Published: December 2007

This case history paper describes a technique that minimizes the creation of multiple fractures in deep coal seams during hydraulic fracturing operations. The technique enabled the operator and the service company to perform 24 nitrogen foam-fluid fracturing treatments in 33 days in the Upper Silesian basin (Poland).

The creation of multiple fractures is a phenomenon often encountered during fracturing operations in coal seams and is the most probable cause of early screenouts. During this fracturing campaign, early screenouts were observed at sand concentrations less than 3 lb/gal. These screenouts were attributed to a lack of fracture width caused by the presence of multiple fractures, including possible horizontal fracture components or tortuosity.

The operator and the service company developed a technique that involves pumping a small volume of highly viscous crosslinked gel before the main fracturing treatment. This technique prevented early screenouts and allowed the higher sand concentrations to be pumped.

P. 237
The Effect of Shales on Mixing in Underground Gas Storage
Authors: Verlaan M.L. , Barzandji O.H.M. , Dronkert H. , van Kruijsdijk C.P.J.W.
Published: December 2007

This paper focuses on an important problem of gas storage projects; the mixing of the cushion gas and the storage gas. Due to mixing, the reproduced gas may not meet customer specifications or valuable gas becomes unrecoverable. In this work we address the effect of shales on the mixing process.

The shales in the gas storage site belong to the 200 m thick Rotliegend sandstone and occur at the base of aeolian facies sequences or are associated with fluviatile intervals between the aeolian dune facies. The horizontal continuity of the shale is strongly facies dependent.

The objective of this paper is to investigate field scale dispersion during cyclic injection and production. Based on shale size distribution we calculate the transfer of gas through shale breaks. This results in an effective dispersion depending on permeability contrast, injected volume and number of cycles.

We observed that shales smaller than the characteristic displacement length contribute to the effective dispersion, while the larger shales do not affect the mixing.

For narrow shale size distributions, the effective mixing is very sensitive to small changes in injection or production volume.

We conclude that shales play an important role in field scale dispersion, and could account for the high dispersivities measured in field tests.

P. 487
An Improved Model for Collapse Pressure of Oval Coiled Tubing
Authors: Zheng Andrew S.
Published: December 2007

This paper presents a new modeling technique to predict collapse pressure of oval coiled tubing. Through finite element analysis, a failure mechanism for tubing collapse is identified and a collapse model proposed. This model relates the tubing collapse pressure with its yield strength, ovality and its D/t ratio. Collapse pressures predicted by this model correlates well with FEM prediction. Collapse experiments were also performed to generate test data for collapse pressure under various ovality. To better simulate the actual material behavior in a typical tubing operation, the ovality in the collapse experiments was generated through a fatigue machine. Predictions from this model are compared against the experimental data as well as other published test data and good agreement is achieved. This new model predicts very well the effect of the ovality and axial force on the collapse pressure. The paper concludes with an introduction to an enhanced software that incorporates this new modeling technique for collapse prediction.

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Collapse Data Analysis and Coiled Tubing Limits
Authors: Avakov Vladamir
Published: December 2007

The paper presents a mathematical model of coiled tubing (CT) collapse pressure (CP), related combined stress, and safety factor evaluation. More than 2,000 collapse-test results for round and long steel tubes were collected from various publications and the API data bank. These data were statistically analyzed and defined to determine the following points about collapse pressure:–CP is a random variable.–CP variation obeys the law of extreme value distribution (not normal distribution) with a definite minimum limit.–CP can be expressed by one relatively simple formula that covers the full practical range of the D/t ratio.–CP can be defined at any required reliability or even at 100% reliability when using the distribution minimum limit.

Derived collapse pressure formulas (CPF's) and the stress factor (safety factor) are supported by test statistics, and therefore enable greater accuracy in CT-collapse prediction.

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Catastrophic Buckling of Coiled Tubing in the Injector
Authors: Newman Ken , Aasen Jan
Published: December 2007

A series of tests were performed to determine the compressive load at which CT will catastrophically buckle between the bottom of the chains and the top of the stripper in the injector. This paper documents these tests and discusses analytical calculations of the buckling load. An equation for calculating the buckling load is given.
Weight on Bit in Coiled Tubing Drilling: Collection and Analysis of Field Data
Authors: Blount C. G. , Hearn D. D. , Payne M. L. , Sathuvalli U. B. , Livesay R.
Published: December 2007

This paper analyzes representative samples of downhole and surface measurements collected during a sidetrack operation with a coiled tubing drilling unit. The downhole data are classified into operational windows such as drill ahead, running in hole and pulling out of hole. They are correlated with drilling reports and surface measurements of hook load, pumping pressures, flow rates, and slackoff. Correlations between the surface and downhole data are used to understand force transmission during set-down, pick-up and drilling operations.
Results From NDE Inspections of Coiled Tubing
Authors: Stanley Roderic K.
Published: December 2007

Service Centre nondestructive inspections of used coiled tubing are being performed in Scotland. This paper outlines the development of an NDE tool for coiled tubing inspection, explaining the principles of operation and presenting some interesting results from several recent inspections, including results on a recent certification test. The current tool performs the following operations for 100% of the tube: detects ID and OD pitting, transverse OD damage and longitudinal damage; locates the areas of heavy cycling; measures ovality and local wall thickness. All detections and measurements are performed by non-contact electromagnetic methods which include magnetic reluctance (MR), magnetic flux leakage (MFL), and eddy current methods for longitudinal flaws, ovality, and the detection of heavily cycled areas. Technique sensitivities are presented.

Data from each inspection can be saved for comparison with future inspections. Such full length NDE, along with fatigue cycling results from flaw removal regions have per- milled strings to be managed by removal of isolated flaws or flawed/worn areas.

Ancillary techniques such as compression wave wall thickness measurement, ultrasonic shear wave and radiographic techniques for the volumetric checking of tube-to- tube welds, and magnetic particle and liquid penetrant techniques for two dimension imperfection detection are also discussed. Evaluation of NDE results will feed into a proposed new API Recommended Practice for Care, Maintenance and Inspection of Used Coiled Tubing in order to provide for standard ways of managing used coiled tubing.

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Novel Coiled Tubing Intervention on an Unmanned Southern North Sea Platform
Authors: Harrison T.N. , Man Y.C. , Moyse B.T. , Malmquist R.D.
Published: December 2007

This paper was prepared for presentation at the 1998 SPE/ICoTA Coiled Tubing Roundtable held in Houston, Texas, 15-16 April 1998.
Development of an Internal Coiled Tubing Connector Utilizing Permanent Packer Technology
Authors: Coronado Martin P.
Published: December 2007

Connecting tool strings to the end of coiled tubing (CT) workstrings has been performed since the advent of CT itself. Early connectors were of the roll-on design, which simply deforms the CT into recessed grooves on the outside of the connector, relying on an interference fit to secure the tool string. As CT applications became more demanding, such as conveying inflatable packers, milling plugs in landing nipples, fishing and drilling operations, the need for higher performance connectors became necessary.

Initial mechanical connectors used set screws inserted through the connector and into the CT and/or external slips which were driven into the outer surface of the tubing to effect an anchor point. These connector designs have proven to be sufficient for normal CT applications, but since they seal and anchor on the outside surface of the tubing they are frequently the largest diameter component of the tool string. This can in many circumstances limit the CT size that can be used.

This paper will describe a new connector design which anchors and seals on the inside wall of the CT, thus allowing the connector to be the same outside diameter (OD) as the tool string, or the CT itself. This eliminates the OD limitation at the connector, and possibly allows larger CT to be used in a specific application, which may offer substantial increases in job efficiency and capabilities (hydraulic horsepower, CT strength, etc.).

The internal connector utilizes permanent packer technology in the seal and slip design, providing high performance. A second generation connector will also be described which allows torque-locking capabilities (connector torsionally locked to the CT), which makes it compatible with CT drilling and milling operations using a mud motor.

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Remote Coiled Tubing Operation Monitoring
Authors: Rosen Patrick M.A.
Published: December 2007

To carry out safe, economical and successful on-and offshore coiled tubing operations it is vital to have at any time access to real time data concerning the physical condition of the coiled tubing as well as information about operational data. Gathering and processing these data on-line with a fully automated coiled tubing operation monitoring system provides the basis for visualizing, managing and sharing necessary information during operations.

This paper discusses the concept for real time coiled tubing data acquisition, evaluation and visualization. It outlines the opportunities and the capabilities of using Internet technology to simultaneous share real timecoiled tubing data among the experts whether on site or at any other place on the globe.

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