bluuebunny/crossref_metadata_2025 huggingface dataset:
Impairment of Gas Well Productivity by Salt Plugging: A Review of Mechanisms, Modeling, Monitoring Methods, and Remediation Techniques
Authors: Aquilina Peter
Published: October 2012

Well productivity decline in mature gas fields, often attributed to liquid loading, may actually be due to salt deposition, which can produce identical symptoms. Salt plugging in gas wells has been well documented in Germany and the USA and is increasingly becoming an issue in the North Sea. There is an increasing awareness amongst North Sea operators of the issue of salt precipitation in gas wells, however, a recent literature search on the subject revealed a limited body of work suitable for use as an introduction to the subject. This paper reviews the mechanisms of salt precipitation, and looks at some modelling and monitoring methods and reviews the available remediation techniques

Salt problems occur over a very limited range of producing conditions and are generally seen in mature, depleted gas fields, explaining perhaps the recent increasing interest in the issue amongst North Sea operators (UK and Netherlands). Salt solubility in water decreases with both reducing pressure and temperature, such as in a producing gas well, so that salt can precipitates as saturated produced water flows up the wellbore. The solubility effects are small but are exacerbated, or exceeded, by dehydration effects as produced water enters the wellbore. Salt may precipitate and adhere to the completion walls and produce a salt bridge. Salt can plug perforation tunnels and even form within the reservoir itself. It is not solely a downhole problem, salt precipitation can occur inside surface equipment such as compressors.

For production operations, early detection or prediction of salt precipitation is vital, yet it has proved difficult as the issue depends on individual well conditions. The paper discusses how diagnostic modelling may help if certain data are available: produced water salinity, operating conditions along the wellbore and reliable WGR history.

Finally, the paper describes current remediation techniques to restore gas well productivity.
Correlation to Predict and Validate the Maximum Retrograde Condensation in Gas Condensate Reservoirs
Authors: Paredes J. E. , Pérez R. , Larez C. J.
Published: October 2012

An important aspect for the exploitation of gas condensate reservoirs is the knowledge of the maximum retrograde condensation, due to the volume of liquid that can be trapped if the pressure reaches the zone where this phenomenon occurs because hardly reaches critical fluid saturation as so it can move toward wells.

This work proposes a correlation that can be used to predict or validate this property, based on the relationship between the maximum retrograde condensation, the molecular weight (MW) of the original composition and its gas oil ratio. A real case analysis is presented which corrects the maximum retrograde condensation measured in the laboratory, reproducing the full curve of this property, without changing the thermodynamic conditions of the fluid.

Also, a conceptual numerical simulation model was built to quantify the behavior and effects if is not corrected the retrograde condensation property in a PVT study.
The Use of a Transient Multiphase Simulator to Predict and Suppress Flow Instabilities in a Horizontal Shale Oil Well
Authors: Norris H. Lee
Published: October 2012

Due to its limited drainage radius, the sand face pressure in a hydraulically fractured, horizontal shale oil well will fall rapidly with cumulative production. Once the sand face pressure falls below the bubble point, flow instabilities will increase dramatically. The onset of instability can be predicted using a transient multiphase simulator such as OLGA1, and techniques to minimize instabilities can be quantitatively investigated through simulation. This paper describes flow instabilities in a typical horizontal shale oil well and demonstrates both causes and remedies for fluctuating production rates in the intermediate and latter stages of well life. Through the suppression of production instability, the ultimate recovery of reserves may be significantly increased.
Experimental Study on Natural Gas Hydrate Slurry Flow
Authors: Lv X. F. , Gong* J. , Li W. Q. , Shi B. H. , Yu D. , Wu H. H.
Published: October 2012

To better understand hydrate slurry flow, a series of experiments have been performed, including water, natural gas and diesel oil, under 4MPa (system pressure), 40Hz (initial pump speed). The experiments have been conducted in a high-pressure hydrate flow loop newly constructed in China University of Petroleum (Beijing), and dedicated to flow assurance studies. A Focused Beam Reflectance Measurement (FBRM) is installed in this flow loop, which provides a quantitative chord length distribution (CLD) of the particles/droplets in the system. Firstly, the influence of flow rate on the hydrate slurry flow was discussed. Then we have studied the factors such as water-cut and additive dosage on the hydrate induction period and the CLD before/after hydrate formation. Finally, we have fitted a new correlation between the dimensionless rheological index, n′, and water-cut as well as additive dosage, according to these experimental results. And a laminar flow pressure model of quasi-single phase hydrate slurry has been established in this paper.
New Upscaling Scheme for Capillary Dominant Displacement
Authors: Behzadi S. H. , Alvarado V.
Published: October 2012

A procedure for upscaling CO2 buoyancy-driven upward migration in finite-difference simulation models is presented in this work. This upscaling procedure allows accounting for effects of capillary and buoyancy forces to enable CO2 upward migration modeling in coarser grids while preserving approximately dominant fine-scaled geological effects. The method has been used in 2D domain simulations with no-flow boundary conditions. The conceptual geological models are built by utilizing sequential Gaussian simulation for different correlation lengths and high level of heterogeneity, Dykstra-Parsons coefficient of 0.7.

Multiphase flow upscaling (MPF) has been improved by accounting for spatial connectivity (percolation), which enabled us to obtain more realistic rock-fluid pseudo-functions and capture effects of local capillary trapping at the fine scale (meso-scale trapping). In contrast with other MPF, e.g. Ekrann (1999) and van Duijn et al. (2002), calculation of rock-fluid functions of each cell has been conditioned by accessibility. Therefore, configuration of coinciding fine-scale cells in a coarse cell affects calculation of upscaled rock-fluid functions. In addition, the effective porous medium properties were estimated using mean field theory (the Maxwell approximation), which considers continuity and isolation of geological facies, responsible for macroscopic residual saturation. The upscaling method and estimation of rock-fluid functions were numerically tested and compared with currently accepted single- and multiphase-flow upscaling methods.

Our results show that single-phase flow upscaling and Maxwell approximation fail to adequately predict mobility and residual saturation. Those upscaling approximations predict gas travel time 7 fold faster. Therefore multiphase flow upscaling should be employed. Significant improvement in gas travel time (representative of mobility) and trapped CO2 saturation (representative of trapped saturation) are observed when spatial connectivity (percolation) is included. Implementation of percolation, improves prediction of gas travel time and residual saturation 21% and 50% respectively.

The developed upscaling scheme lowers simulation execution time 17 fold through upscaling and noticeably enhances the prediction of phases mobilities and macroscopic trapped saturation. This speedup will enable simulating 3D CO2 sequestration simulation scenarios. The scheme can also serve to scale up other subsurface multiphase flow displacement where capillary force is dominant one.
Laboratory Study of Sand Production in Unconsolidated Reservoir
Authors: Luo Weiguo , Xu Suxin , Torabi* Farshid
Published: October 2012

Sand production is a major operational and economical concern in the oil industry due to the potential risk of well failure, limited productivity, erosion of facilities, and increased operating expense. Experimental studies play an important role in understanding the behavior of sand production under different conditions. However, the existing traditional sand production experiments such as thick-walled, cylinder approach or perforation collapse test are only able to predict the onset of sanding and cannot be used to analyze sand production performance over time. In this work, preliminary empirical sanding prediction was performed based on well log data and the formation mechanical properties. The steady-state core flooding tests and core swelling tests were applied to simulate and investigate how the volumetric sand production changes with different flow rates, water saturations and the salinity of injected water. The cores and crude oil samples from an unconsolidated sandstone reservoir in China were used in the tests. The sand flow rate, accumulative sand volume and relative permeability were measured during the sand production process.

The experimental results indicated that the sand production rose at the beginning and declined with the increase of flow rate. During the early water-free production stage, the skeleton sand was not destroyed under realistic reservoir/well flow conditions so that the oil production with sanding was preferred. However, as water saturations increased from 20% to 80%, the permeability decreased by 80% accompanied by dramatic increase in sand production. This is due to the high content of Kaolinite, Illite and Montmorillonite with weak cement in the core which swells significantly and blocks the porosity once it is subjected to the water influx. Therefore, sand control should be considered when water saturation is over 20%. The change of sand production rate demonstrated that both the transient and continuous sand production could be involved in this reservoir. In addition, it is expected that the lower salinity of injected water aggravates the sand production.
Integrated Approach to Unconventional Reservoir Characterization: Key for Understanding Hydrocarbon Production Challenges in Kerogen and Tight-Fractured Deep Carbonate Complex in Kuwait
Authors: Acharya Mihira N. , Kabir Mir R. , Al-Ajmi Saad H. , Al-Maia Noura A. , Kumar Ashok , Pradhan San P. , Al-anzi Ealian H.
Published: October 2012

The unique Kimmeridgian-Oxfordian complex of unconventional and fractured carbonates has been tested to be prolific producer of gas, condensate and light oil in different wells discovered in various North Kuwait fields. The challenge is to characterize the complex reservoir flow system where critical reservoir parameters such as reservoir type, porosity and permeability characteristics, and production and pressure data can vary substantially.

The relationship between the natural fractures and the tight matrix in controlling effective system conductivity in reservoir flow units are the key features which dictate the nature of inflow mechanisms thus the production performance. The paper deals with developing an effective methodology which integrates the variations in critical reservoir properties of the low porosity yet naturally-fractured carbonate reservoir.

The drill stem test (DST) results in some wells were successful without stimulation, while in other wells the DSTs were unsuccessful in spite of advance and repeated stimulations, thus categorizing these plays as geologically-complex, tight gas condensate reservoirs where out of ordinary stimulation techniques may be needed to activate the fractured matrix. Pressure transient analyses and flow regime interpretation of the successfully-tested wells confirm the dual porosity flow-system and the fractured nature of the reservoir.

In this paper, the authors will discuss a new integrated approach for understanding the production and pressure behavior in light of the unique unconventional reservoir characteristics along with the fractured reservoir properties. Dual-layer and dual poro-perm models for pressure transient analysis have been applied extending the previous study of relationship developed between the productivity index (PI) and the total organic carbon (TOC). The proposed integrated methodology can significantly improve the current approach to production optimization, reservoir management strategy, completion, and stimulation design in fractured tight gas condensate reservoirs in Kuwait as well as in other regions.
Channel Characterization for Acoustic Downhole Communication Systems
Authors: Farraj Abdallah K. , Miller Scott L. , Qaraqe Khalid A.
Published: October 2012

The ability to communicate between downhole and surface instruments became a critical need as well operators monitor flow rate, temperature, and pressure data to facilitate well performance optimization and maintenance. The use of wire lines for communication between downhole and surface is common, but these installations present cost, maintenance, and reliability issues. Wireless communications technology using acoustic waves is an interesting alternative to these wired systems. While the acoustic technology offers great benefits, a clear understanding of its propagation aspects inside the wells is lacking.

A testbed was built to investigate the propagation of acoustic signals over production pipes. The testbed comprises an acoustic tool that transmits data to the well surface without cables, an internally-developed receiver unit, and five segments of 7 inch production tubing that form a pipe string. Acoustic waves propagate in this setup by vibrating the pipes’ body, without interfering with the surrounding medium. Moreover, to study the effect of cemented pipes on wave propagation, the third pipe segment was encased in concrete. An impulse signal was fed to the acoustic tool, and channel impulse response readings were taken along the pipe string. The measurements were analyzed to understand the propagation aspects of acoustic waves.

This work shows that acoustic waves experience dispersion and frequency-dependent attenuation over the pipe string; the pipe string appears as a frequency selective channel. The concrete segment filters out a considerable amount of energy in the higher frequency band and introduces further attenuation and dispersion. Signal processing algorithms are proposed to reduce the distortion and dispersion introduced by the pipe string channel on the acoustic waves.

Technical contributions include: finding the impulse response of the channel along the pipe string, investigating the power delay profile, power spectral density, and signal-to-noise ratio measures, and studying the channel dispersion parameters.
Solving Swelling Clay Issues: Modeling Effort/Concentric Reamer Saves Operator Over Seven Days Rig Time vs Plan, UK North Sea
Authors: Snowie Mike , Alexander Gregg , Duncan Roy , Alemi Hassan , Jolly Iain , Barlow Adam
Published: October 2012

The operator requires a 12¼" tangent borehole through interbedded shale, chalk/sandstone that contains hydratable montmorillonite clay, Auk North field, UK North Sea. The swelling clay and long open-hole section have proven troublesome creating hole cleaning issues, frequent wiper trips and stuck pipe events.

A comprehensive modeling project was initiated with the aim of reducing vibration whilst improving rate of penetration (ROP) by selecting the best drive system, bottom hole assembly (BHA) configuration and combination of operating parameters. A rock strength program was run and indicated unconfined compressive strength (UCS) of the Oligocene/Eocene formations at 2-10kpsi. Analogous formation samples were selected from the rock library and laboratory tests were conducted to replicate actual drilling conditions. The resulting data was then entered into the finite element analysis (FEA) based modeling system. A 12¼" × 14" concentric reamer equipped with three polycrystalline diamond compact (PDC) triple row cutter blocks, a pilot PDC bit and a rotary steerable system (RSS) were selected for the investigation. Dynamic simulations were preformed with various operating parameters to observe how changes influenced BHA performance.

The analysis provided valuable insight when the bit and reamer are drilling non-homogeneous formations. The weight-on- tool fluctuation creates BHA instability which can be mitigated by managing parameters. A driller's roadmap was produced showing optimum weight on bit (WOB)/revolutions per minute (RPM) combinations that would produce stable drilling for different formation scenarios.

The integrated BHA was run with the recommended parameters and drilled 5889ft in three runs at an average ROP of 77ft/hr. The BHA met all directional objectives with low lateral vibration and medium stick-slip levels. All cutting structures used showed minimal wear. The successful run enabled the operator to complete the section seven days ahead of authority for expenditure (AFE) plan.
The Use of Two Phase Compressibility Factors in Predicting Gas Condensate Performance
Authors: Arukhe Inese Ntuk , Mason W. E.
Published: October 2012

Gas condensate reserves are typically underestimated when single phase compressibility factors are applied to two-phase systems. The effect is worse in rich gas condensate system with adverse implications for gas initially in place (GIIP) estimation, gas reserves, petroleum accounting, and pipeline designs. Accurate prediction of GIIP early in the life of a reservoir is therefore crucial in reaching development decisions and contractual agreements.

Underestimation of reserves often results from approximations based on single phase (Standing and Katz) compressibility factors that do not consider two-phase regions that retrograde condensate reservoirs exhibit at pressures below the dew point. During isothermal pressure reduction below the dew point phase changes occur leading to liquid and gaseous phase separation in the reservoir. Consequently, there is need to introduce a two phase Z factor in material balance calculations to account for the phase changes in the reservoir.

Ideally, Z-factors for gas reservoirs are determined from constant volume depletion (CVD) tests that simulate compositional changes during reservoir depletion. Sometimes the CVD test reports are not readily available or plans are non-existent for PVT data acquisition campaign. A methodology that employs a suitable correlation developed using fluid molar composition or gas gravity of reservoir fluid to obtain two-phase Z-factors (Z2p) is described. This compares quite well with actual data for retrograde condensate systems.

This paper describes a correlational research design with two-phase Z-factor derived from the real gas law equation and single phase Z factor from Rayes et al (1992) to determine GIIP for gas condensate reservoirs. Z-factors were also determined from Dranchuk Abu-Kassem (1975) correlations using pseudo-reduced properties presented by Sutton (1985) and Kay (1936) mixing rules. The paper compares Z2p, Z-factors, GIIP values obtained from the CVD test and correlations and establishes that the two-phase Z-factor should be used for more precise estimation of GIIP in gas condensate reservoirs.
Effects of Gas Additions to Deepwater Gulf of Mexico Reservoir Oil: Experimental Investigation of Asphaltene Precipitation and Deposition
Authors: Gonzalez Doris L. , Mahmoodaghdam Elham , Lim Frank , Joshi Nikhil
Published: October 2012

Conventional primary and secondary water flooding of Deepwater Gulf of Mexico (GOM) reservoirs typically result in substantial un-recovered oil providing an attractive target for enhanced oil recovery (EOR) processes. One of the challenges of applying EOR gas injection in these offshore reservoirs is the h igh oil asphaltene content. Anadarko Petroleum Corporation and Schlumberger have jointly investigated the effects of gas addition on the phase behavior of oil, especially its effect on asphaltene precipitation and deposition. The study focuses on the experimental results from various tests showing the instability of asphaltenes in oil from various gas injection scenarios.

Three common EOR injection gases: nitrogen (N2), carbon dioxide (CO2) and methane (CH4) were studied. N- heptane was (n-C7) also included for comparison of solids phase behavior during depressurization. Most asphaltene laboratory testing use n-C7 at ambient conditions, whereas asphaltene precipitation occurs with change in pressure and temperature during reservoir depletion processes.

The study collected PVT and flow assurance data for original live fluid and for additions of N2, CO2, CH4 and n- C7 at high pressure and temperature conditions. Measurements include asphaltene onset pressure (AOP), saturation pressure (Pb), swelling tests and asphaltene deposition tests. Other basic measurements of the corresponding dead oil include SARA analysis, viscosity, density and fluid characterization. Fluids from the field presented a compositional variation with a variety of asphaltene contents from 4 to 15.5%.

Results of experimental flow assurance assessments revealed the black oil has high propensity for asphaltene precipitation due to addition of injected gas. The addition of N2, CO2 or CH4 significantly aggravates the asphaltene precipitation condition of these fluids.

The comparison between the three gases showed that, when added in the same mole proportion, N2 was the strongest precipitant followed by CH4.
Reservoir Connectivity Analysis Using Long Term Interference Testing in a Waterflood Pilot in the Carbonate Marrat Formation of the Greater Burgan Field, Kuwait
Authors: Gazi Naz , Ali Farida , Al-Naqi Meqdad , Dashti Laila , Al-Qattan Abrar , Al-Farhan Farhan
Published: October 2012

Interference testing although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of establishing communication between wells and determining the reservoir transmissibility in the region.

This paper discusses the methodology and results obtained from a four month pressure data acquisition campaign for a transient interference test performed in a carbonate reservoir known as Marrat, in the Giant Burgan field of Kuwait.

The Marrat long term interference test was conducted around a water injector pilot with distances as far as 0.9 km at the subsurface locations between the injector and producer wells. Therefore, the interference test was used to evaluate the transmissibility between the injector and the nearby observation wells. The producer wells were shut-in for the entire length of the test so as not to create any disturbances that could hinder the interpretation processes. After conducting this test, a better understanding of the subsurface uncertainty as well as communication between the wells was highlighted. Other objectives were added to the tests which were to determine the water bank distance from the injector, as well as to describe the least resistive path that the water prefers to travel in.

The tests showed that not all the wells responded to the pressure pulse, and therefore the assumption that a fault was isolating one of the wells. One of the main conclusions was a strong directional transmissibility that was at first associated with a high permeability corridor corresponding to the depositional environment. The other conclusion was the orientation of the fracture plane which could cause this high directional transmissibility. A comparison and integration of the acquired pressure data with a separate geologic stochastic model was constructed and discussed in this paper.

Based on the integration work of the interference test and the geologic study it was therefore concluded that a secondary recovery using water flooding would be beneficial and necessary for sustaining Marrat reservoir production in the long term based on the location of both producer and injector wells.
Extreme HPHT Wireline Data Acquisition: Planning for Success
Authors: Owens J. , Parry G. , Taylor B.
Published: October 2012

Data acquisition in extreme environments of high pressure and/or high temperature (HPHT) with pressures up to 30,000 psi and temperatures up to 500°F requires not only specialist technology capable of surviving these conditions, but also many months of preparation and planning to ensure a successful operation.

The aim of this publication is to provide an overview of what is involved in the planning, preparation and execution of an extreme HPHT wireline data acquisition, from the customer setting the information objectives through to data delivery. This includes developing an agreed quality plan between the data provider and the customer covering testing and deployment of the latest extreme HPHT logging equipment.

All aspects must be considered to minimize risks including detailed tailoring of the logging programmes to manage time in hole, ensure accurate depth control and by employing a deployment risk management process, to ensure that what goes in the hole comes out again.

The implementation of these procedures is illustrated with a case history of a series of HPHT exploration wells drilled in the Central Graben of the North Sea (the "HPHT Heartland" of the North Sea). Bottom hole conditions were predicted to approach 400°F and 15,000 psi. These extreme conditions negated the use of conventional wireline tools and so, from initial early planning discussions between client and service provider, new detailed programmes were designed and implemented as a specific "Quality Plan" to use the advanced HPHT wireline logging tools.
Integrated Reservoir Delineation and Development of Deep, Tight Carbonates: Kuwait Case Study
Authors: Al-Anzi Ealian H. , Rao Narhari Srinivasa , Al-Ashwak Samar , Kidambi Vijaya Kumar , Al-Ajmi Neema Hussain , Rao Jonna Dayakar , Al-Ateeqi Khalid , Al-Mayyas Rawan Hussain , Al-Anzi Abdullah Motar , Allan Stefanic Odreman , Acharya Mihira N. , Chakravorty Sandeep , De Kyser Tom
Published: October 2012

Deep, tight carbonate reservoirs of Pliensbachian, Sinemurian, and Hettangian Stages of the mid-Mesozoic Era are becoming very important in the continued pursuit of hydrocarbon prospects in North Kuwait. At present, a total of 21 wells have penetrated the targeted reservoir zones. Of these, 12 have been tested for hydrocarbon production covering a large area of about 1700 sq km. Further, six wells have produced oil and gas, with two deemed commercially successful.

The entire workflow to characterize these reservoirs is focused on delineating faults and associated fractures in individual wells. Detailed seismic study and volume curvature maps, revealed the existing fault and fracture corridors. Sub-seismic faults and subtle reverse faults with fractures were detected by log correlations and borehole image. Due to paucity of cores in these zones, descriptions of cuttings samples were used to identify faults and fracture zones, based on the presence of large euhedral crystals in the midst of cryptocrystalline dolomite, suggesting the percolation of hydrothermal fluids through fractures.

Many of the wells were drilled with an overbalanced mud system, leading to near-borehole porosity and permeability damage to the rock matrix and to the fracture system. Damage to natural fractures intersecting the well can prevent their detection, leading to missed potentially productive intervals. Mobility of hydrocarbons in these tight, fractured carbonate reservoirs depends upon (i) wells intersecting a natural fracture system that is sufficiently permeable and connected to a large volume of reservoir rock and (ii) the near-borehole area not having suffered irreversible damage due to overbalanced drilling.

In summary, the proposed reservoirs are very tight carbonates (average 3 pu porosities) and a fracture play is considered to be the key factor in production. Acid stimulation produced multifold increases in productivity. Most of the wells were drilled overbalanced, which has negative impact on the producibility due to formation damage.
First Fully Sulfide Stress Cracking Resistant Drillpipe System
Authors: Jellison Michael , Redlinger Thomas , Howie William
Published: October 2012

As the severity of sour drilling applications has increased, the requirement for drill stem materials resistant to sulfide stress cracking (SSC) has accelerated. Sour service drillpipe, traditionally manufactured with SSC resistant upset tubulars and tool joints, has been available for some time. Sour Service drillpipe metallurgy is not specifically controlled by NACE MR 0175/ISO 15156,1 however these tubulars and tool joints are often evaluated in accordance with the standard. The friction welds joining the upset tubulars and tool joints were not resistant to SSC and were not evaluated. This has been acceptable for many sour drilling applications since the weld is not the mostly highly stressed region of the drillpipe joint and because the operator has a certain degree of control over the environment through the drilling fluid properties and additives. As more severe environments with higher Hydrogen Sulfide (H2S) concentrations were identified for exploration and development, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary.

This paper presents the successful development and qualification of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy employed, laboratory testing procedures with results presented and applications for the SSC resistant drillpipe. Since NACE MR 0175/ISO 15156 does not address friction welds the engineering team developed unique and innovative criteria together with testing procedures for the new weld technology. A new patent pending four-point bending test procedure and fixture were developed that employed unpolished samples that represent the surface finish of the product in service, in contrast to the polished samples used in NACE TM0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. The paper can benefit drilling engineers involved in critical sour drilling operations.
A Variational Approach to the Numerical Simulation of Hydraulic Fracturing
Authors: Bourdin Blaise , Chukwudozie Chukwudi , Yoshioka Keita
Published: October 2012

One of the most critical capabilities of realistic hydraulic fracture simulation is the prediction of complex (turning, bifurcating, or merging) fracture paths. In most classical models, complex fracture simulation is difficult due to the need for a priori knowledge of propagation path and initiation points and the complexity associated with stress singularities at fracture tips.

In this study, we follow Francfort and Marigo's variational approach to fracture, which we extend to account for hydraulic stimulation. We recast Griffith's criteria into a global minimization principle, while preserving its essence, the concept of energy restitution between surface and bulk terms. More precisely, to any admissible crack geometry and kinematically admissible displacement field, we associate a total energy given as the sum of the elastic and surface energies. In a quasistatic setting, the reservoir state is then given as the solution of a sequence of unilateral minimizations of this total energy with respect to any admissible crack path and displacement field. The strength of this approach is to provide a rigorous and unified framework accounting for new cracks nucleation, existing cracks activation, and full crack path determination (including complex behavior such as crack branching, kinking, and interaction between multiple cracks) without any a priori knowledge or hypothesis.

Of course, the lack of a priori hypothesis on cracks geometry is at the cost of numerical complexity. We present a regularized phase field approach where fractures are represented by a smooth function. This approach makes handling large and complex fracture networks very simple yet discrete fracture properties such as crack aperture can be recovered from the phase field. We compare variational fracture simulation results against several analytical solutions and also demonstrate the approach's ability to predict complex fracture systems with example of multiple interacting fractures.
Transitional Kick Tolerance
Authors: Santos Helio , Sonnemann Paul
Published: October 2012

Kick Tolerance (KT) is commonly defined as the maximum volume of a given type of influx (typically gas) which can be successfully contained and circulated out of a well using the Driller's Method. Used properly, many companies believe KT calculations help to quantify safety margins that exist between expected wellbore conditions and incrementally higher well design limits. However, one big issue in the industry today is the lack of consistency about KT calculation, leading to significant confusion and increased risk. Situations occur when drilling a well in which one company involved may argue that there is enough KT to keep drilling, whereas another company argues the opposite. Another factor limiting the value of most kick tolerance methods employed today stems from almost exclusive focus on the KT at the end of a hole section, without accounting for erratic trends of pore pressure and possible deviations from the drilling program. Confusion and lack of standards regarding KT often prevents effective use of the concept to assess the risks while drilling. After a brief introduction describing the two most common methods used to calculate KT, the paper presents an example highlighting the limitations and issues when using the current approach to calculate KT. In the example, KT is sufficient to meet various company policy requirements, but control of the well is lost when a kick within original well design limits enters the well. The concept of Transitional Kick Tolerance is then introduced, which has been developed to overcome the limitation caused by focus on single point KT calculations and which provides substantial benefits in the context of changes that occur while drilling the section.
First Successful Rigless Conversion of Subsurface Safety Valves from Tubing Retrievable to Wireline Retrievable in the Middle East
Authors: Yateem Karam S. , Hanbzazah Shadi M. , Alsyed Samih M. , Fouad Alaa , Mahamed Saleh M.
Published: October 2012

In the oil and gas industry, safety systems are put in place to prevent the release of hydrocarbons and protect assets against any undesirable events. This can be accomplished by installing protective measures that monitor the process components, and can also control the process in case of undesirable events. The Surface Controlled Subsurface Safety Valve (SCSSSV) is one major component, which is mainly installed in wells that are located offshore or close to populations and environmentally sensitive areas. These SCSSSV can be categorized into two types depending on the deployment/retrieval methodology. The first type is referred to as the Wire Line Retrievable Subsurface Safety Valve (WLRSSSV), which is installed and retrieved by rigless well intervention and installed inside the production tubing. The other type is the Tubing Retrievable Subsurface Safety Valve (TRSSSV) and these valves are part of the tubing completion.

Due to its numerous advantages, like full bore access, and not to retrieve the valve before any intervention, TRSSSV are gaining more popularity. Saudi Aramco uses these types of valves and most of the new completions are designed with TRSSSV. Unfortunately, as these types of valves are part of the completion, any failure to close these valves results in a disturbance in the safety system of the well, which will lead to performing an expensive workover, which is not only costly but the process means killing the well, and therefore inducing damage to the reservoir.

This paper presents in detail the procedure applied to these inoperable TRSSSVs to regain the safety of the wells and put them back on production without the need to de-complete the well. The direct business impacts are restoring the well safety system, wells’ productivity in addition to cost avoidance of (onshore and offshore) workover operation to replace the malfunctioning TRSSSVs. The paper will also cover common mitigation measures to mitigate TRSSSV failure and avoid their conversion.
Implementing Knowledge-Sharing Systems and Establishing a Culture to Share Lessons Learned Within a Multidisciplinary Company Enhancing Effective Knowledge Transfer
Authors: Hinze Iris , Perry Phil , Jacob George T. , Wise Wade V.
Published: October 2012

Today's oil and gas industry relies increasingly on integrated multi-disciplinary services to provide effective risk management, wellbore and reservoir delivery while minimizing operating costs, cost of failure and non-productive time (NPT). New collaboration technologies enable the rapid storage, transfer and consumption of information and require robust but flexible knowledge management techniques to fulfill the requirements of a global learning organization.

New tools need to be developed and successfully implemented tools need to be expanded to enable cross-disciplinary teams and communities the ability to capture, share and reuse validated knowledge efficiently. This paper presents how a single-domain lessons-learned system was extended to represent the entire spectrum of the upstream industry; assuring interdisciplinary information is reusable in multiple communities and market segments.

The paper presents the challenges inherent in leveraging a common classification scheme; lessons-learned framework, enterprise platform, and search-and-retrieval systems with the goal of connecting people and making the collective knowledge seamlessly accessible across different business units, time zones and geographies.

Also discussed is how building a common framework and incorporating the lessons-learned system into communities of practice, training and certification programs helps drive acceptance/implementation of the program.

Finally, we showcase how the system has been used to deliver game-changing performance in time savings to locate relevant information and how re-use of stored knowledge enables performance improvements in wellbore delivery.
Production Increase with Electric Heating Production Line Technology in an Extra-Heavy Oil Field in Colombia: Successful Case of Flow Assurance
Authors: Escobar-Remolina J. C. , Barrios W. , Ecopetrol S. A , Silva B.
Published: October 2012

In recent years the oil industry has focused primarily on the exploitation of heavy and extra-heavy oil reservoirs. On the other hand these crudes represent current worldwide one of the greatest potential contributions to reserves to the energy industry. The production, treatment and transportation of these crudes are a real challenge, because these crudes increase the viscosity exponential from the reservoir to the gathering collection plant. This causes a dramatic increase in the well pump pressure system, reducing the production capability of the lifting system and optimal management of fluids, resulting in lost in the flow assurance system committing millions of dollars annually in non-effective remedial techniques. This article describes a successful case of flow assurance technology application to an extra-heavy oil of 9.0 °API, using electric heating of the well production line along 900 meters in a Colombian oil field. The selected well to apply this technology increases its daily oil production over 160%, well head pressure decreases 95%. Chemical dosification was optimized and BS&W values required by the control system were reached by heating technology. Additionally, lighter crude of 25 °API, used as a diluent, to move this extra-heavy oil through the production line was avoided in 100%.
Forecasting Gas Production in Organic Shale with the Combined Numerical Simulation of Gas Diffusion in Kerogen, Langmuir Desorption from Kerogen Surfaces, and Advection in Nanopores
Authors: Shabro V. , Torres-Verdín C. , Sepehrnoori K.
Published: October 2012

We introduce a new numerical algorithm to forecast gas production in organic shale that simultaneously takes into account gas diffusion in kerogen, slip flow, Knudsen diffusion, and Langmuir desorption. The algorithm incorporates the effects of slip flow and Knudsen diffusion in apparent permeability, and includes Langmuir desorption as a gas source at kerogen surfaces. We use the diffusion equation to model both lateral gas flow in kerogen as well as gas supply from kerogen to surfaces.

Slip flow and Knudsen diffusion account for higher-than-expected permeability in shale-gas formations, while Langmuir desorption maintains pore pressure. Simulations confirm the significance of gas diffusion in kerogen on both gas flow and stored gas. Relative contributions of these flow mechanisms to production are quantified for various cases to rank their importance under practical situations.

Results indicate that apparent permeability increases while reservoir pressure decreases. Gas desorption supplies additional gas to pores, thereby maintaining reservoir pressure. However, the rate of gas desorption decreases with time. Gas diffusion enhances production in two ways: it provides gas molecules to kerogen-pore surfaces, hence it maintains the gas desorption rate while kerogen becomes a flow path for gas molecules. For a shale-gas formation with porosity of 5%, apparent permeability of 59.7 μD, total organic carbon of 29%, effective kerogen porosity of 10%, and gas diffusion coefficient of 10−22 m2/s, production enhancements compared to those predicted with conventional models are: 9.6% due to slip flow and Knudsen diffusion, an extra 42.6% due to Langmuir desorption, and an additional 61.7% due to gas diffusion after 1 year of production. The method introduced in this paper for modeling gas flow indicates that the behavior of gas production with time in shale-gas formations could differ significantly from production forecasts performed with conventional models.
Autonomous Spilled Oil and Gas Tracking Buoy System and Application to Marine Disaster Prevention System: Part 1
Authors: Kato N. , Senga H. , Suzuki H. , Okano Y. , Ban T. , Takagi Y. , Yoshie M. , Tanaka T. , Sakagami N.
Published: October 2012

This paper describes the ongoing project on autonomous spilled oil and gas tracking buoy system and application to marine disaster prevention system for 5 years since FY2011. The objectives of this project are as (1)autonomous tracking and monitoring of spilled plumes of oil and gas from subsea production facilities by an underwater buoy robot, (2)autonomous tracking of spilled oil on the sea surface and transmission of useful data to a land station through satellites in real time by multiple floating buoy robots, (3)improvement of the accuracy of simulations for predicting diffusion and drifting of spilled oil and gas by incorporating the real-time data from these robots.
Using Nitrogen for Extended Reach in Coiled Tubing Operations
Authors: Fiazudeen Mohamed
Published: October 2012

In the oil industry, there is always a need to go deeper and cheaper. Coiled tubing's greatest advantage is being able to operate without a rig, cutting costs and time by a great extent. To this day, coiled tubing has been used for many well services like cementing, stimulation, cleanouts, drilling, production, perforation etc. As this technology gains fame and takes the place of the jointed string, the need for its versatility also increases. Coiled tubing is highly used in horizontal wells for its flexibility. Unfortunately, due to its small size, there are higher chances of tubing getting locked up in the process of intervention. To extend its reach, a number of tools and techniques like friction reducers, tapering tubing, tractors etc. have been invented and been used. However, these tools and techniques can only be used on a case by case basis.

This paper introduces buoyancy reduction, one other technique to extend the reach of coiled tubing in horizontal wells. The concept behind this technique is to reduce the net weight of the tubing by creating a buoyancy effect. This is done by pumping a very light fluid into the tubing while intervention to create a large difference in the densities of the annular and the tubular fluids. The higher density of the annular fluid creates a buoyancy effect on the tubing and thus reduces the drag against the well floor. Moreover, the low density fluid also increases the rigidity of the tubing and makes it follow a transverse wave pattern, similar to that of a free flowing garden hose. Both the lower weight and the transversal wave motion of the tubing help it to wriggle its way into the well. In this case, simulations showed an extended reach of 23%.

Each well may need a different technique for extended reach. As per the requirement of the case, a combination of these technologies can be used to reach the planned measured depth. Buoyancy reduction is one other technology that is available for use that is easily implementable at minimal added cost.
A Novel Simulation Model Review Process
Authors: Palke M. R. , Palmer B. A. , Rietz D. C.
Published: October 2012

Throughout the upstream petroleum industry, reservoir simulation models have become the standard tool used to make a myriad of decisions regarding the development and operation of oil and gas assets including decisions regarding investments and reserves estimates.

Given the variety of decisions that rely on this technology, petroleum engineers are frequently required to opine on how well an unfamiliar model might fit a particular purpose, and how accurate it might be for that purpose. Generally speaking, engineers must go through some sort of review of the model before any opinion of fit and accuracy can be developed.

The authors have written or contributed to several papers that began to address the process for performing such simulation model reviews for various purposes (see Palke and Rietz 2001, and Rietz and Usmani 2005). This paper attempts to advance this work by presenting a systematic and quantitative methodology for performing these reviews, as well as discussing why such reviews are necessary and some of the potential pitfalls encountered while reviewing simulation models.
Martin Linge Extended Well Test: a Key Acquisition for the Field Development Decision
Authors: Boutaud de la Combe Jean-Luc , Kvinnsland Steinar , Marmier Remy , Morante-Gout Jenny
Published: October 2012

The Martin Linge field was discovered in the 1970's but never developed due to a number of uncertainties. The complex structural settings of the Brent reservoirs was the main issue: transmissibility through the numerous faults has a direct impact on the number and type of development wells required for an appropriate drainage of the field, hence on the economy of the project

In 2009/2010 Total drilled an innovative appraisal well to de-risk this challenging development. The primary objective was to evaluate the dynamic connectivity through faults on the Upper Brent level of Martin Linge East with an Extended Well Test (EWT)

A program for the EWT (6 months duration), was defined and implemented in order to ensure conclusive results for the development strategy.

The well design included an innovative completion system with acoustic wireless down-hole gauges and a communication system to transfer the pressure data up to sub-sea well-head and then to shore via a communication link. This made it possible to obtain extended pressure build-up data after the rig had left. The test targeted the uppermost Brent reservoir of Balta only.

Analytical models were used to evaluate the investigated volume. This volume turned out to be significantly greater than the Balta reservoir accumulation, proving that the faults allow communication not only laterally but also vertically with the underlying Upper Brent Tarbert reservoir.

Due to the structural complexity of the field and the large investigation, the Eclipse reservoir model was also used to match the EWT data with the earth model. The EWT simulations in this model highlight the high lateral and vertical connectivity through major faults

Thanks to the EWT results, a marginal field was successfully turned into a robust development project