bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Operations in Statoil - From Ambition to Action
Authors: Lilleng Trond , Øyen Mette , Farestvedt Unn , Engelsen Harald , Nordbø Hilde , Vennes Berit , Revheim Aleksander , Seim Ole , Halvorsen Teresa
Published: June 2014

During 2007 – 2009 Statoil performed a series of steps to enable integrated operations (IO). This included introduction of standardized work processes, a common operating model for Statoil-operated fields on the Norwegian Continental Shelf (NCS) and an IO guideline based on seven IO success criteria, ref. SPE 128576. During 2010 a mapping of IO capabilities based on Statoil's IO guideline and requirements was performed for 28 Statoil-operated NCS fields for selected work process aspects within drilling, production optimization and operations and maintenance. The purpose was to map the degree of IO compliance in relation to the common operating model and identify improvement opportunities within each of the field units.

The mapping was based on a questionnaire of 190 questions and was distributed to 590 persons within the field units. The response to the survey was very satisfactory (79%). To supplement the questionnaire the IO team performed meeting observations and analysis of supplementary data and KPIs for each field. Best practice was identified for most work process aspects and used as a reference for improvements across assets. All the data were treated statistically to limit uncertainties and bias. The mapping project identified IO improvement opportunities within the individual field units, as well as common improvement projects across fields/assets. The paper addresses the challenge of scaling with respect to IO implementation, from selected work processes and individual production installations to broad implementation for Statoil's NCS operations.

The IO mapping project documented the value of utilizing the IO guideline and capability model as basis for identifying actionable improvements with respect to integrated operations in a systematic manner for a large number of assets. The paper describes the method, main results and experiences gained from the project.
A Stack Model and Capabilities Approach to Investigate Integrated Operations Across Different Industrial Sectors – O&G Industry versus Aviation, Military and Medicine
Authors: Larsen Sjur , Bjørkevoll Knut Steinar , Gibson Andrew K. , Gunnerud Vidar , Lien Dag Ola , Thorvik Ketil , Nystad Arild N.
Published: June 2014

This paper adopts a capability and stack model approach to a study of what the oil and gas industry can learn from three selected sectors: military, medicine, and aviation. First, the paper gives an introduction to the stack and capability approach to IO. Next, a preview of common challenges across sectors is provided. Finally, the paper gives examples of cutting-edge developments in medicine, military and aviation, and demonstrates potential learning for the oil and gas industry.
Oil Recovery From Thin Heavy-Oil Reservoirs: The Case of the Combined-Thermal-Drive Pilot in the Morgan Field
Authors: Gutiérrez Dubert , Ursenbach Matthew G. , Moore R. Gordon , Mehta Sudarshan A.
Published: June 2014

The Morgan field in Canada produces from the Lloydminster and Sparky sands, which are thin heavy-oil reservoirs. Early development of the pool was with primary vertical wells in the late 1970s, with some enhanced-oil-recovery (EOR) projects [e.g., cyclicsteam stimulations (CSSs) and in-situ combustion (ISC)] attempted in the early 1980s. However, the area was essentially noncommercial after the 1986 oil-price collapse. In order to regain commerciality, the operators implemented progressing cavity pumps (PCPs) and horizontal drilling, which have proved to be a success. Even with these advances, though, recovery is estimated to be less than 10% of the original oil in place (OOIP). One of the EOR projects attempted was the combined-thermal-drive (CTD) pilot, which was carried out in one of the sections of the field for 10 years. After a brief primary-production period, the CTD pilot began in 1980 and consisted of three stages. In the first stage, CSSs were performed on individual wells during the first 2 years. In the next 4 years, air was added to the injection stream to perform cyclic air/steam stimulations on individual wells. In the last stage, pressure cycling in-situ combustion was performed for approximately 4 years. In this paper, historical production and injection records were gathered to perform a technical and economic analysis of the project. After approximately 20 years since the shutdown of the project, the data indicate that this pilot has outperformed all of the other operations carried out in other areas of the field. Not only has it produced the largest amount of incremental oil of all the sections of the field, but it also managed to sustain high production rates for 10 years, which is unparalleled in the area. On the economic side, the data indicate that the project was experiencing difficulty because of the 1986 oil-price collapse. However, an economic analysis under current oil prices and costs suggests that it would have been both a technical and an economic success. This air-injection case history represents a good opportunity for those operators facing the challenge to develop thin heavy-oil reservoirs.
A New Model for Reservoirs With a Discrete-Fracture System
Authors: Zeng Fanhua Bill , Zhao Gang , Liu Hong
Published: June 2014

Dual-porosity and dual-permeability models for naturally fractured reservoirs assume that the fractures in the reservoir are connected with each other and uniformly distributed. However, in some cases, the reservoir characteristics exhibit a discrete-fracture system, which means that the fractures might be unconnected and their distribution is not uniform. In this paper, a new computational model is developed to compute the transient-pressure behaviour for reservoirs with a discrete-fracture system. This computational model is based on Laplace transforms. The fluid flow in the fracture system and reservoir are computed separately, and flux and pressure equivalent conditions in Laplace space are applied in the fracture wall to couple the fluid flow in both systems.

The results suggest that the pressure response in a reservoir with a discrete-fracture system has three flow regions: fluid flow near the wellbore, fracture-dominated fluid flow, and fluid flow in the matrix away from the fracture. The distance between the fracture and the well, fracture parameters (fracture conductivity and non-Darcy effects), and fracture distribution are the main factors affecting the pressure response. In some particular situations, the fracture-dominated fluid-flow region in the pressure-derivative curve may present two valleys, which has been observed in some field cases (Clarkson 2009). The transient-pressure behaviour of a discrete-fracture system is also compared with that for a composite model. It is suggested that in these two scenarios, the early- and middle-time transient-pressure behaviour may be similar and latetime behaviours are quite different. The model provides a tool for identifying the fracture pattern in a specific reservoir.
Improving Drilling Performance in the Upper Cretaceous: A Case Study From Santos Basin, Brazil
Authors: Flores S. , Fagundes L. , Irokawa Y. , Schmidt A. , Quinones H. , Landinez G. , De Oliveira P.C. , Ramos A. , Medina Y.
Published: June 2014

The Upper Cretaceous is a challenging drilling environment in Santos Basin, offshore Brazil. The lithology consists of highly intercalated layers of sandstone, siltstone and conglomerate from Santos and Jureia Formations. These formations are drilled vertically in 17 ½" intermediate hole and the length of the section varies from 1600 m up to 2000 m. Optimizing the drilling efficiency in this section is crucial to reducing drilling costs and non-productive time.

During a recent exploratory campaign in Santos Basin, severe levels of shocks and vibrations were encountered while drilling this large and intercalated hole section, resulting in a low rate of penetration, premature bit wear, damaged tools, unplanned trips and drill string failures. Three to four bit runs were required to reach section TD.

Post job information and drilling data were reviewed by an integrated operator-contractor team. A detailed engineering analysis of bit, BHA design and drilling mechanics was conducted to address the challenges of this section and propose a new approach to the drilling process. The key was the determination of the best combination of WOB and RPM to drill the different lithologies, together with more stable PDC bits, use of downhole motors and combined with specific operational procedures to mitigate shocks and vibrations.

The proposed changes in bit selection and BHA configuration, drilling parameters and procedures, real-time monitoring and training have been successful. For the first time in the drilling campaign in Santos basin, it has proved possible to drill the 17 ½" hole in one bit run. The section was finished without any incident, under budget and under time.

The improvement in drilling performance achieved with the implementation of this engineering study helped the operator to mitigate shocks and vibrations and save money, thus ensuring a more efficient drilling operation and preventing further drill string failures.
Simulation of Coupled Flow and Mechanical Deformation Using IMplicit Pressure-Displacement Explicit Saturation (IMPDES) Scheme
Authors: El-amin M. F. , Negara A.. , Salama A.. , Sun S..
Published: June 2014

The problem of coupled structural deformation with two-phase flow in porous media is solved numerically using cell- centered finite difference (CCFD) method. In order to solve the system of governed partial differential equations, the implicit pressure explicit saturation (IMPES) scheme that governs flow equations is combined with the the implicit displacement scheme. The combined scheme may be called IMplicit Pressure-Displacement Explicit Saturation (IMPDES). The pressure distribution for each cell along the entire domain is given by the implicit difference equation. Also, the deformation equations are discretized implicitly. Using the obtained pressure, velocity is evaluated explicitly, while, using the upwind scheme, the saturation is obtained explicitly. Moreover, the stability analysis of the present scheme has been introduced and the stability condition is determined.
Acidizing Sandstone Reservoirs Using HF and Formic Acids
Authors: Yang F. , Nasr-El-Din H. A. , Al-Harbi B.
Published: June 2014

Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures.

In this study, formic acid was used to remove carbonate minerals as a preflush and with the main HF stage. A series of formic acid and HF mixtures with different ratios and concentrations were tested. Sandstone cores featured by different minerologies with dimensions of 1.5 in. x 6 in. were used in the coreflood experiments, which were run at a flow rate of 5 cm3/min and temperatures from 77 to 350°F. The cores were analyzed by CT scan before and after the acidizing to investigate the effect of the acid. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP. 19F NMR was utilized to follow the reaction kinetics and products. Zeta potentials of clay particles (kaolinite, illite, and chlorite) were measured in various acid solutions

Formic acid (9 wt%) damaged sandstone cores. Zeta potential measurements indicated that formic acid can trigger fines flocculation. Addition of 5 wt% ammonium chloride helps to shield negative charges on clay surface. Analysis of core effluent samples indicated that there was CaF2 precipitate in the core when a small volume of preflush was used. Coreflood tests highlighted that formic acid/HF caused loss of core permeability. This paper will discuss the detailed chemical reactions occurred within cores and were followed by chemical analysis of core effluent samples and 19F NMR. Secondary reaction between clay minerals and HF became faster at higher temperature, and decreased the ratio of Si/Al. It was also found that different clay minerals react with HF offering very different concentrations of Al and Si in spent acid.
A Systematic Study of Different Delayed Systems for Mudcake Removal in High-Temperature Horizontal and Multilateral Wells
Authors: Najeeb P. P. , Alkhaldi M. H. , AlFaifi M. G.
Published: June 2014

Effective removal of drilling-mud filter cake during well completion is essential to reduce the formation damage caused by drilling activities in many production and injection wells. This task is very difficult to achieve, especially in horizontal/multilateral wells. Harsh chemical treatments (acids, oxidizers, and chelating agents) have been used extensively to conduct water-based mudcake cleanup treatments. However, these approaches have been limited due to the associated high corrosion rates and un-even mudcake removal. With their controlled reaction with the mudcake, mild chemical nature, better health, safety and environmental (HSE) profile, different acid-precursor systems provide an excellent alternative to harsh chemical treatments in high temperature formations.

This work examines the efficiency of two acid-precursor systems to be used for mudcake removal in horizontal wells. These two acid-precursors (an ester of acetic and formic acid) will generate acid at slow rate at downhole conditions, resulting in uniform mudcake removal. The acid release rate of both in-situ acid generator systems was calculated at targeted average reservoir bottom-hole temperature of 130°F. The study was conducted at simulated reservoir conditions of 500 psi pressure for building the filter cake and 300 psi pressure for soaking the treatment. Drill-in fluids (DIF) sample collected from the field was used for conducting the filter cake removal tests. Return permeability experiments were performed using HPHT filter press cell.

Filter cake removal efficiency of formate ester showed that this system removed 59.3 wt% water-based mudcake formed on a 5 μm ceramic disk when soaked for a prescribed period of 24 hours at 130°F and 300 psi nitrogen pressure. Similarly, filter cake removal efficiency of acetate ester tested on similar conditions removed 30.4 wt% of the filter cake. The break through time for the reactive fluid to penetrate through the mud filter cake was found to be approximately 15 hours for formate ester. Acetate aster system breakthrough was found to be nearly 7 days. Compared to acidic brine (1 wt% HCl), these systems will have slower fluid loss rates where the amounts of collected filtrate were found to be 14.6, 2.7, and 2.5 cm3 for 1 wt% HCl, formate ester and acetate ester, respectively, after soaking time of 2 hours.
Axial Excitation and Drill String Resonance as a Means of Aiding Tubular Retrieval - Small Scale Rig Testing and Full Scale Field Testing
Authors: Forster Ian , Grant Robert
Published: June 2014

This paper describes the work carried out at NOV Downhole on an in house designed and built, small scale, vibration test rig which was developed with the purpose of studying the effect of axial excitation on tubular retrieval.

There are currently well established downhole tools that aid tubular retrieval by way of introducing axial excitation into the drill string fish- with resulting reductions in overpull requirements.

The mechanism for overpull reduction during axial excitation is by way of effectively fluidizing the media surrounding the tubulars and thereby reducing the frictional forces holding them.

By exciting drill string resonances of the fish during the axial excitation process, it is possible for the tubular retrieval fish to behave as a dynamic vibration absorber – a characteristic of which is to increase its response amplitude. This will effectively enhance the fluidizing process.

During the rig testing, it has been possible to compare the Axial Excitation Tool performance at drill string fish resonance frequency with other frequencies. The rig tests demonstrate significant increase in fish response amplitude with the Axial Excitation Tool present at the resonance frequency.

Full scale field operations where an Axial Excitation Tool technology has been applied have resulted in significant overall reductions in overpull.

During the field tests, axial excitation tool and tubular retrieval fish response was intended to be measured and recorded using the black box system. However, this has yet to be achieved, but still remains a future objective.

Never the less, the results for the cased studied so far have validated the rig tests and mathematical modelling.

With reference to offset data, the paper presents actual field data that demonstrates significant reductions in time spent during tubular retrievals, and the corresponding cost savings.
Experimental and Computational Study of Flow Characteristics in a Drilled Perforated Core
Authors: Sun Datong , Satti Rajani , Ochsner Darren , Sampson Tim , Li Baoyan , Gladkikh Mikhail
Published: June 2014

In recent years, the oil and gas perforation industry has seen the growth of several perforation flow laboratories to experimentally measure the flow characteristics of perforated cores. In such experiments, the determination of core flow efficiency (CFE) depends on the theoretical flow rate in addition to the measured flow rate. Usually, an average core axial/radial permeability is used to calculate the theoretical flow rate, thereby neglecting the heterogenic/anisotropic nature of the core. In this study, we examined the significance of considering the core heterogeneity/anisotropy through experiments and a computational fluid dynamics (CFD) approach.

In this study, a cylindrical Berea sandstone core sample (7-in. diameter x 30-in. length) is drilled axially using a custom drill, with a 1-in.-diameter hole and 3.25-in.-length increments through the core. Flow characteristics were measured under axial flow boundary conditions for each drilling depth of the core. Further, multiple axial/radial core plugs were extracted and routine core analysis was conducted on these core plugs to measure the localized porosity and permeability. Subsequently, the experimental data was complemented by conducting numerical simulations using commercial CFD software for each perforation length.

For the case where the average axial permeability from experiments was used directly in the CFD simulations, significant discrepancies in equivalent permeability were found between experiments and simulations. Subsequently, CFD simulations using the localized permeability of axial core plugs showed good agreement with experiments. It was also found that CFD results using the localized permeability of all axial and radial core plugs provided similar results as compared to using only the axial core plugs. It can be inferred from the above results that core axial heterogeneity is very important for perforation flow prediction and the anisotropy has minimal effect on the CFD results for this Berea core.

Therefore, this study provides insight into the importance of axial permeability heterogeneity to calculate CFE for a perforated core flow under axial flow boundary condition in the perforation flow lab. It also plays an important role in the development / validation of numerical models and more importantly evaluating shaped charge performance for perforated core /well-scale scenarios.
Hydraulic Fracture Optimization in Unconventional Reservoirs
Authors: Saldungaray Pedro , Palisch Terry T.
Published: June 2014

Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs. From tight gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial viability.

A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral. Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the lateral, the fracture isolation technique and job size. Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique.

While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity receives lesser attention. Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as "infinitely conductive" features. However, many factors that affect the realistic conductivity of the fracture are poorly understood or overlooked. This often leads to a less than optimal outcome with wells producing below the reservoir potential.

This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics, are considered among other variables. The theory behind this concept is presented and supported with case studies where it has been applied in the field to various unconventional reservoirs.
Eliminating Stick-Slip by Managing Bit Depth of Cut and Minimizing Variable Torque in the Drillstring
Authors: Davis Joshua E. , Smyth Gregory F. , Bolivar Neil , Pastusek Paul E.
Published: June 2014

During extended reach drilling operations, stick-slip was identified within the operator’s Fast Drill Process™ workflow as the primary performance limiter in the 8-1/2-in. hole section. This dysfunction resulted in low penetration rates, frequent downhole tool failures, and bit damage. Subsequently, multiple bit runs were required to reach interval objectives.

The redesign process identified two key solutions to mitigate stick-slip vibrations. First, the bit was redesigned to limit (or manage) the depth of cut to reduce the torque variations which can excite stick-slip. Second, the torsional stiffness of the drillstring was increased by changing from 5-1/2- to 5-7/8-in. drillpipe, which reduced the magnitude of the torsional oscillations. The systematic application of these design changes allowed higher weight on bit (WOB) to be applied without stick-slip dysfunction, resulting in significantly higher penetration rates.

This paper presents the results of applying depth of cut control and drillstring design to eliminate stick-slip while drilling. Weight-on-bit, vibration, and penetration rate data will be presented over the course of eight wells. Results indicate the managed depth of cut and increased torsional stiffness provided significant reductions in vibrations leading to multiple field record rate of penetrations (ROPs), improved downhole tool life, and reduced bit damage.
Formation Damage Due to CO2 Sequestration in Deep Saline Carbonate Aquifers
Authors: Mohamed I. M. , Nasr-El-Din H. A.
Published: June 2014

CO2 injection in carbonate formations causes a reduction in the well injectivity, due to precipitation of the reaction products between CO2/ rock/brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO2 injection.

Limestone rocks represent the homogenous rock in this study, and include: Pink Desert limestone and Austin chalk, which are mainly calcite. Silurian dolomite (composed of 98% carbonate minerals, and 2% silicate minerals) and Indiana limestone rock represent the heterogeneous rock, which have some vugs in their structure.

Coreflood experiments were conducted to compare the behavior of the permeability loss between these rocks. CO2 was injected with the water alternating gas (WAG) technique. Different brines were examined including seawater and no sulfate seawater. The experiments were run at a pressure of 1300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A compositional simulator tool (CMG-GEM) was used to confirm the experimental results obtained in this study.

The results showed that for homogenous rocks, the presence of sodium sulfate in the injected seawater is the major factor that causes formation damage, due to calcium sulfate precipitation in CO2 environments. For dolomite rocks, higher damage was noted, due to the reactions of CO2 with the silicate minerals. For both homogenous and heterogeneous rocks, the source of damage for high permeability cores is the precipitation of reaction products, while for low permeability cores, water blockage increases the severity of formation damage. The simulation study showed that the power-law exponent, and Carman-Kozeny exponent between 5 and 6, can be used for homogenous carbonate rock to estimate the change in permeability based on the change in porosity, for heterogeneous rock a larger exponent was needed.
Improvements in Production Liner Cementing for Coiled Tubing Drilling
Authors: Johnson Mark O. , Milne John R. , Diller Carl W.
Published: June 2014

Since 1994 Coiled Tubing Drilling (CTD) has completed over 650 sidetracks on the North Slope of Alaska. In many aspects the window milling and drilling phase can be considered a mature technology. However, recent developments in the completion phase namely with the generation II side exhaust liner running tool (Gen II SELRT) have further increased job reliability, safety, and efficiency for the liner cementing completion phase.

This paper will begin with a brief update on the status of CTD on the North Slope (3 rigs drilling on a daily basis) and discuss how many of the challenges with drilling through/below the production tubing have been dealt with. The cost for a CTD sidetrack with an equivalent amount of reservoir exposure and zonal isolation is about one half that of a rotary sidetrack on the North Slope. This is due to efficiencies in leaving the production tubing in place (dominant savings) and less consumables. In addition, CTD’s enhanced capability for underbalanced drilling (UBD) and managed pressure drilling (MPD) make it attractive for some North Slope fields.

While the electronically controlled drilling bottomhole assembly (BHA) has improved drilling performance, the electric line (EL) inside the CT has challenged the completion phase. CT wiper darts for separating cement from displacement fluid can no longer be used. The CT wiper dart would be damaged by the EL and visa versa. Instead, the new liner running tool discussed in this paper exhausts the contaminated cement/mud interface to the annulus at top of liner before launching the liner wiper plug (LWP).

Over 76 liners have been cemented with the side exhaust technique. The last 34 jobs have been done with the Gen II SELRT that uses mechanical dogs to close the path through the LWP, side exhaust, and launch the LWP when desired. This new tool increases job efficiency over the first generation tool and continues to provide reliable liner cementing with EL in the coil.
Use of Liner Drilling Technology as a Mitigation to Loss Intervals and Hole Instability: A Case Study in Mississippi Canyon
Authors: Rosenberg Steven M. , Gala Deepak M.
Published: June 2014

Liner drilling technology provided an effective solution to hole instability issues seen while drilling with conventional methods through a narrow mud weight/pore pressure/fracture gradient window laden with depleted intervals and virgin pressured shales in the Mississippi Canyon block of the Gulf of Mexico.

Two 8-1/2" x 9-1/2" wellbores were lost while drilling with Rotary Steerable Systems (RSS) in the 60° wellbore. The initial wellbore was lost as a result of RSS failure resulting in the hole packing off. A subsequent bypass wellbore encountered catastrophic lost circulation resulting in the hole collapsing as the depleted commercial sand came in unexpectedly high. In each case this resulted in the loss of the RSS Bottomhole Assembly (BHA).

Liner drilling technology was identified as the most appropriate strategy for setting the 7-5/8" drilling liner and 5-1/2" production liner because:

Documented lost circulation problems have been minimized or eliminated through prior use of DwL technology, largely attributed to the "smear effect" phenomenon. The narrow annular geometry created by liner drilling reduces the rate of fluid loss in the annulus as compared to conventional drilling operations enabling effective management of the annular fluid level. DwL systems historically minimize or eliminate non-productive time in operations in which uncontrolled fluid losses have been encountered previously.

Ultimately, the correct application of liner drilling technology on this well allowed the operator to reach the intended drilling depth and completion objective. The equipment selection, operation, and results of the liner drilling operations will be presented in the paper.
Interventionless Surveillance in a Multi-Lateral Horizontal Well
Authors: Andresen Christian , Williams Brock , Morgan Mike , Williams Theresa , Crumrine Tim , Bond Andy , Franks James
Published: June 2014

Reservoir developments that rely on long horizontal wells are common practice. Understanding the inflow distribution from a horizontal well is an ongoing challenge for our industry. The effectiveness of reservoir management decisions are greatly improved with an understanding of the flow distribution across the reservoir interval.

While technologies have been developed using tractors or coiled tubing to deploy production logging tools into horizontal wells, it requires a well intervention operation, increases risk exposure and is not always successful.

This paper reviews a case study from a multi-lateral well in Alaska where a new style of chemical tracers embedded into the completion equipment was used to derive a quantitative estimate of the inflow distribution in a dual horizontal, multi-lateral well.

The chemical tracers, which resemble strips of plastic, are designed to release unique chemical fingerprints when contacted by oil. The tracers are then detected in the oil to concentrations as low as 1 part per trillion. In this case study six locations were selected for placement of oil sensitive tracers.

During a shut-in period the strips continue to release their unique chemical tracers causing an increased tracer concentration to develop in the oil immediately surrounding the tracer location. Upon start up, these small volumes of oil, containing the higher concentration of tracer, are displaced to the surface. Samples of the produced oil are analyzed to develop a plot of each tracer’s concentration vs produced volume. The arrival of the oil containing the high tracer concentration is related to the inflow distribution.

This paper reviews results from a field deployment in a dual lateral well that contained 3 tracer locations in each lateral. The results from this well indicate that one lateral was producing approximately 30% more than the other lateral. Additionally the data indicates the toe of one of the laterals was a major contributor to the total well flow.

This insight into the reservoir performance was obtained with no intervention into the well and only minor modifications to the completion design.
Contractual Language Needed to Help Reduce Integrated Control Systems Risk on High-Specification Assets
Authors: O’Grady Bill
Published: June 2014

Control systems software is a mission-critical component of the drilling control, dynamic positioning, power, subsea, and vessel management systems on high-specification offshore assets. The unique features of this mission-critical software cannot be adequately addressed using the same contractual language that provides Performance, Quality, Health, Safety, and Environmental (PQHSE) assurances for hardware systems; software-specific language is also needed.

Unfortunately, most contracts in the oil and gas industry do not articulate software-specific PQHSE expectations. This often results in non-productive time (NPT) and health, safety and environmental (HSE) risks during operations. Effective contractual software standards:

Are based on an internationally recognized body of standards and guidance Establish expectations for measuring ongoing control systems software PQHSE levels through inspection, auditing, and testing Encourage vendor-stakeholder collaboration and shared accountability Enable control systems software to be continually improved

This paper will help Drilling Contractors, Operators and Shipyards develop and leverage contractual software standards to create an environment in which:

Vendors and stakeholders can work together to improve systems quality onboard high-specification assets All parties involved in asset construction and operation are appropriately accountable for helping to ensure that software-related issues do not result in NPT or HSE risk
The Effects of Back Rake and Side Rake Angles on Mechanical Specific Energy of Single PDC Cutters with Selected Rocks at Varying Depth of Cuts and Confining Pressures
Authors: Rajabov Vusal , Miska Stefan , Mortimer Laurence , Yu Mengjiao , Ozbayoglu Evren
Published: June 2014

One of the key objectives within the drilling industry is optimizing rate of penetration (ROP) and a major contributor to obtaining this objective is the PDC bit design. Whilst previous papers have proven that the PDC cutting structure geometry, particularly back rake and side rake angles, affect PDC bit performance when tested at atmospheric conditions, no information in the SPE literature exists for similar tests at confining pressures. The effect of side rake angle on cutter aggresiveness and cutter interaction at depths of cut (DOC) in excess of 0.04” are particularly unknown under confined pressure.

The results of more than 150 tests show that back rake and side rake angles have substantial effects on Mechanical Specific Energy (MSE) and the aggressiveness of PDC cutters. Experiments with three different rock types; Carthage marble, Mancos shale, and Torrey Buff sandstone, revealed that at both atmospheric and elevated confining pressures, PDC cutters with 10 deg back rake angles require half the energy to cut the same volume of rock and produce higher cutting efficiency compared with cutters having 40 deg back rake angles. Possible reasons for this behavior are explained through the analysis of the cutting process.

Results show that a cutter with low back rake requires less horizontal cutting force in order to cut the same volume of rock. This observation indicates that not only will a PDC bit with lower back rake angles, drill more efficiently, but it will also require less torque in order to drill at the same ROP. Other factors such as reduced durability of cutters at low back rake angles should also be considered while applying these results to PDC bit designs.

Test results at both atmospheric and confining pressures revealed that MSE decreases with increasing DOC up to 0.08” on all three rock types. However, the tests also showed that MSE starts to increase slightly at DOCs above 0.08”, possibly suggesting an optimal minimum DOC.

Experimental results also show that, whilst Mancos shale and Carthage marble have about the same compressive strength, Mancos shale requires three times less energy to cut compared to Carthage marble. This indicates that, compressive strength of some rocks such as shales cannot be used alone as a reference rock property for accurately evaluating and comparing drilling efficiency.

A new 3D mechanistic PDC cutter-rock interaction model was also developed which incorporates the effects of both back rake and side rake angles, along with rock specific coefficient of friction. The results from this single-cutter model are encouraging as they are consistent with the experimental data.
Rheological Properties of Invert Emulsion Drilling Fluid under Extreme HPHT Conditions
Authors: Lee John , Shadravan Arash , Young Steve
Published: June 2014

Limited amount of rheological data generated under extreme high-pressure, high-temperature, (HPHT) conditions (>500°F/30,000 psi) have been published due to lack of suitable viscometer and drilling fluid for such conditions. This paper compares the rheological properties of invert emulsion drilling fluid generated from four types of HPHT viscometers and provides a simple rheological model that can be used to predict the behavior of OBM under extreme-HPHT conditions.

Previously most of the HPHT studies were limited to 20,000 psi and 500°F. Recently more than one extreme-HPHT rheometers have become commercially available, which can measure the rheological properties of drilling fluids at conditions up to 600°F and 40,000 psi. These viscometers have been used to test various invert emulsion drilling fluid samples to the maximum capacity of the equipment. Parts of the data generated from one particular instrument have been compared with data obtained from other rheometers that are operated at lower temperature and pressure.

The data indicated several factors can critically affect the rheology measurements, including drilling fluid chemistry, instrument set up and test schedule. Rheological properties measured by various instruments differed slightly from each other perhaps due to design differences. Temperature and pressure not only affect the rheological properties of the test fluid but may also impact the performance of the critical mechanical parts used for rheology measurement. In addition, HSE experience gained from working with extreme-HPHT instruments is also included in this paper.
Improving Casing Wear Prediction and Mitigation Using a Statistically Based Model
Authors: Mitchell Sarah , Xiang Yanghua
Published: June 2014

Wells are now routinely drilled both in deepwater and on land to depths that were previously considered impossible. In these environments, casing design is critical to safely and successfully drilling and producing wells, and unexpected casing wear can result in significant costs or even the loss of a well. As part of a successful casing design strategy, the engineer must assess the maximum permissible casing wear required to maintain casing integrity. Then, steps must be taken to ensure that casing wear thresholds are not exceeded.

Casing wear models use the number of drill string revolutions and contact force between the drill pipe and casing to calculate wear. The contact force is calculated using the dog-leg severity within the well, with the maximum dog-leg severity often determining the location and extent of the most severe casing wear. There is often a large discrepancy between predicted and actual casing wear because of survey quality and inaccurate estimates of dog-leg severity and total revolutions. These discrepancies result in predictions of contact force and drill string revolutions that are in error by 50% or more. To improve the accuracy of casing wear models, an extensive database was created from a wide variety of wells with measured depths greater than 13,000ft. The database results in a statistically based model for determining dog-leg severity within vertical, build, and tangent sections, as well as total drill string revolutions at various levels of confidence to bound average and maximum expected contact force and casing wear.

Case histories compare measured wear with predictions of casing wear based on original well data and the statistically based model. The case histories also demonstrate the effect of various drilling parameters on casing wear, and evaluate the effectiveness of non-rotating protectors in preventing casing wear.
Real-Time Motor and Turbine Performance Monitoring and Optimization
Authors: Ringer M. , Johnson A. , Barrett M. , Goldsmith G. , Flint G. , Mao S. , Terracina D.
Published: June 2014

We present the results from a field test in which both a drilling turbine and a positive displacement motor were instrumented to provide real-time measurement of their shaft speed. This permitted the construction, in real-time, of the actual performance characteristics of the motor, and immediate feedback as to the driller’s operating point on the motor’s power curve. By determining the actual performance curves of the motor in real-time, we were then able to operate the motor at a desired point on its power curve and significantly increase ROP without inducing a single motor stall.

The test also highlighted potential differences between the published and the actual downhole performance curves of the motors, as well as the ability to track changes in the motor’s performance over time.
PDC cutter and Bit development for challenging Conglomerate Drilling in the Luno Field - Offshore Norway
Authors: Hellvik Svein , Nygaard Runar , Hoel Espen , Andersen Mats , Francis Mark
Published: June 2014

The Luno discovery in the Norwegian sector of the Southern North Sea, with an estimated 180 million recoverable barrels of oil (Greater Luno area including Tellus) in a conglomerate and sandstone reservoir, has proven to create unique drilling challenges. The reservoir, planned with horizontal or 60° slanted producers and inclined water injectors, consists of both sandstones and conglomerates with granite clasts of varying sizes.

During the exploratory phase the conglomerate was mainly cored with diamond impregnated bits. The recorded rate of penetration (ROP) through the conglomerate spanned from 0.5- to 3.5-m/hr; for most of the time it stayed at between 1- and 2-m/hr. Reduced well cost was one of the early identified major potential field development savings if the conglomerate can be drilled with polycrystalline diamond compact (PDC) bits capable of an ROP of 10- to 15-m/hr, and which would last for 500- to 1000-meters reservoir sections.

To investigate the feasibility of using PDC bits, after reaching the target in appraisal well 16/1-13, the well was deepened utilizing two different types of PDC test bits. After the PDC field tests were conducted with the first bit ringed out after 70 meters and the second bit partially worn out after 34 meters of rough drilling, it was decided to initiate a PDC development project to develop a PDC bit with cutters that could withstand the challenging drilling of the conglomerate for the upcoming field development/production phase. A "conglomerate pie" test block was manufactured and used in a vertical turret lathe to conduct single cutter PDC testing. Utilizing the improved wear and impact resistance of the new enhanced cutters developed based on results from the testing, an experimental bit with different cutter types was used in another well with hard basement rock. From the cutter and bit performance observed during the field test, further laboratory- and field testing was conducted with these cutters showing preliminary performance results of 3- to 4-times initial durability potential for a constant ROP.
Sand Consolidation in the Mahakam Delta: 3 Years Later
Authors: Chaloupka V. , Descapria R. , Mahardhini A. , Coulon D. , Tran Q. , Haekal M. , Santoso D. C. , Amar A. , Nusyirwan A.
Published: June 2014

Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. Most of the wells are multizone gas producers completed with cemented tubing without primary sand control, and are produced with a bottom-up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallower reservoirs prone to sand production were not targeted until recent years. With progressing depletion of deep reservoirs in the Main Zone and bottom up perforation strategy the operator started perforating upper zones. This resulted in an increasing number of interventions or shutting wells in due to sand production.

Due to this fact the operator started considering remedial sand consolidation about 5 years ago. The first successful trials using internally catalysed epoxy resin fluid were prepared in late 2008 and results presented at the 2010 SPE International Symposium and Exhibition on Formation Damage Control (Chaloupka et al. 2010). Initially, these consolidation treatments aimed to find a remedial solution for existing wells choked back or shut in due to sand production. These successful trials, however, quickly turned the project into using consolidation essentially as a primary sand control method.

First treatments targeted weakly consolidated sands in both Tunu and Tambora fields (5,000 to 8,000 ftTVD) using high temperature internally catalysed epoxy consolidation fluid. The treatments showed encouraging results and confirmed this as a viable option for sand control.

In 2010 with growing confidence in the method the operator considered performing sand consolidation in very shallow fully unconsolidated Tunu Shallow zones (2,300 to 5,000 ftTVD) as an alternative to standard single trip multi-zone gravel packs which are conventionally pumped in Tunu Shallow. Five treatments have been performed using a low temperature version of the consolidation fluid with encouraging results. The preliminary performance envelope validated from the treatment is 3 MMscfd of gas per meter perforated or a drawdown of 300 psi.

The paper aims to describe the experience from the initial trials to field application including placement and fluid QAQC procedures as well as treatment results. The failures and difficulties that have been encountered are looked at in more details.
Vibration Analysis in Riserless Conditions
Authors: Samuel Robello
Published: June 2014

Riserless drilling poses numerous operational challenges that adversely affect the efficiency of the drilling process. These challenges include increased torque and drag, buckling, increased vibration, poor hole cleaning, tubular failures, poor cement jobs, and associated problems during tripping operations. These challenges are closely associated with complex bottomhole assemblies (BHAs) and the vibration of the drillstring when the topholes are drilled directionally. Current methods lack proper modeling to predict drillstring vibration.

This paper presents and validates a modified model to predict severe damaging vibrations, analysis techniques, and guidelines to avoid the vibration damage to BHAs and their associated downhole tools in the riserless highly-deviated wells. The dynamic analysis model is based on forced frequency response (FFR) to solve for resonant frequencies. In addition, a mathematical formulation includes viscous, axial, torsional, and structural damping mechanisms. With careful consideration of input parameters and judicious analysis of the results, the author demonstrates that drillstring vibration can be avoided by determining the 3-D vibrational response at selected excitations that are likely to cause them. The analysis also provides an estimate of relative bending stresses, shear forces, and lateral displacements for the assembly used. Based on the study, severe vibrations causing potentially damaging operating conditions were avoided, which posed a major problem in the nearby wells.

The study indicates that the results are influenced by various parameters, including depth of the mud line, offset of the wellhead from the rig center, wellbore inclination, curvature, wellbore torsion, and angle of entry into the wellhead. This study compares simulated predictions with actual well data and describes the applicability of the model. Simple guidelines are provided to estimate the operating range of the drilling parameter to mitigate and avoid downhole tool failures.