EXPLORATION, INDIVIDUAL EQUIPMENT: QUICKSILVER
Schlumberger

Probe sets benchmark for fluid evaluation

Schlumberger's QuickSilver Probe addresses the fundamental problem of openhole formation fluid analysis: uncertainty due to the contamination of the fluid sample with drilling mud filtrate. With knowledge of the reservoir physics, a new tool design and a technique called focused sampling, this tool makes it possible to achieve negligibly low contamination samples in shorter station time.
The probe can be used in temperatures up to 350°F (175°C) and 25,000 psi.
A comparison of conventional and focused sampling is shown in Figure 1 to illustrate the new technology. During a conventional sampling operation, fluid withdrawn from the reservoir shows continuously diminished contamination with filtrate entering the perimeter of the sampling zone. The achievement of zero contamination in fluid samples is theoretically impossible with this technique, and this theory has been proven over years of practical application.
With the QuickSilver Probe, the new design separates the pure reservoir fluid entering in the center from the contaminated fluid entering the perimeter of the probe. The contaminated fluid is pumped into a separate flow line, isolated from the pure reservoir fluid collected in a sampling flow line.
An operator in the Gulf of Mexico issued a challenge to achieve a sample contamination level of less than 5% in a key exploration well. Because of the use of oil-based mud, higher filtrate contamination levels would result in uncertainties in lab analysis. Previous attempts to reach the client's target level confirmed the difficulty of the task, with contamination levels at 40%. Using the QuickSilver Probe in the same well and formation resulted in contamination levels of less than 3% in less time.


EXPLORATION, SYSTEM: NEW REMOTE SENSING TECHNIQUE
EMGS

Electromagnetic surveys find hydrocarbons

Seabed logging is a new remote sensing technique that has emerged in the last 3 years as the preeminent technology for finding commercial quantities of hydrocarbons in offshore reservoirs. Developed by Electromagnetic Geoservices AS (EMGS), this proprietary application of controlled-source electromagnetic marine (CSEM) surveying offers operators a fundamentally new insight into the physical properties of the subsurface, including the presence of electrically resistive hydrocarbon accumulations.
Revisiting the physics of electromagnetic (EM) propagation in the subsurface in the late 1990s, Terje Eidesmo and Svein Ellingsrud, then working for Statoil, showed that low-frequency EM energy, emitted by a source close to the seafloor, could propagate to the depths typical of hydrocarbon reservoirs. They also showed that resistive subsurface bodies guide EM energy with low attenuation over long distances. Seabed logging can indicate the presence of commercial offshore hydrocarbon reservoirs by recording energy propagated far from the source in this way.
Uptake of seabed logging has been rapid, with more than 125 commercial surveys recorded by EMGS. Statoil's Linerle discovery and a major Shell discovery in the Far East were predicted by seabed logging before drilling. Both companies participated in the initial trials of the technique and continue to be prolific users. Now many other major, national and independent operators are using the technique to reduce exploration risks and locate commercial reservoirs in pre- and post-license phases.
Seabed logging has been included in the work commitments of several operators awarded acreage in Norway's recent licensing round. Other national licensing authorities are also either requiring or accepting seabed-logging data for evaluation of drilling commitments. Together, these developments confirm seabed logging as a mainstream exploration tool.

SUBSURFACE CHARACTERIZATION, INDIVIDUAL EQUIPMENT: HSFT
HALLIBURTON

Tool suitable for HT/HP environments

Halliburton's Hostile Sequential Formation Tester (HSFT) is a new wireline formation tester designed specifically for high-temperature, high-pressure (HT/HP) environments, providing data on pressure and fluid mobility and giving sampling capacity in HT/HP well bores.
It has a slimhole design and can operate in temperatures up to 400°F (205°C) and 25,000 psi.
The tool's capability to access reservoirs in environments that previously had been inaccessible helps meet the need for formation tester data in all wells. These data include pore pressure, fluid mobility and fluid sampling. In gas development areas, determining inert gas contents such as CO2 and N2 levels is often very important, along with measuring the gas energy levels. Water samples that yield water saturation values are useful in conjunction with traditional log analysis, particularly in exploratory areas.
The HSFT was introduced in the Gulf of Thailand 3 years ago and, to date, has performed more than 300 successful runs without a single stuck tool or fishing job. The runs cover a range of well types including exploratory/delineation, initial platform development, and infill development oil and gas wells. More than half the wells logged exceed 350°F (175°C) and all have been drilled with a synthetic oil-based mud. Well deviations can reach up to 65°, and infill wells often encounter highly depleted zones. The combination of slimhole design and the surface-controlled releasable cable head have allowed success in hole access for wireline conveyance.

SUBSURFACE CHARACTERIZATION, SYSTEM: CHI MODELING SYSTEM
HALLIBURTON

System creates synthetic openhole logs

Halliburton's Chi Modeling System generates accurate synthetic "triple-combo" (resistivity, neutron porosity and density) openhole logs from cased-hole pulsed neutron capture (PNC) logs. This technology can eliminate the requirement for running openhole logs in most new wells in many fields and can also provide synthetic open-hole logs in almost all older cased wells. This also results in savings of rig time associated with running logs in uncased holes and reduces the risk of stuck tools containing radioactive sources. This capability greatly facilitates cost-effective acquisition of logs and their correlations in maturing and mature fields.
The resulting simulated openhole logs reproduce with high accuracy the triple-combo logs, facilitating the use of familiar log interpretation and correlation methods. Often the nuclear data obtained are more accurate than would be expected from conventional tools, particularly in logging-while-drilling environments.
Applications include water saturation and net pay calculations, well-to-well correlation, production monitoring, stimulation and completion design, bypassed hydrocarbon identification, and reservoir characterization.
Since 2003, more than 1,000 synthetic triple-combo logs have been processed using the Chi Modeling System. Nuclear sources were therefore eliminated from these jobs, and operators have saved 25% to 80% on logging costs alone.

WELLBORE CONSTRUCTION, INDIVIDUAL EQUIPMENT: RAPTOR THERMOSTABLE PDC CUTTER
REEDHYCALOG

Low cutter wear in high temperatures

Traditional multimodal PDC cutter material wears rapidly in high temperatures because the diamond graphitizes as it gets hot. Raptor Thermostable PDC cutters overcome this problem. By changing the chemistry of the surface of the polycrystalline diamond layer, a Thermostable outer layer of material is formed. This material is 200% more heat-resistant and 400% more abrasion-resistant than any polycrystalline diamond.
The Thermostable outer layer significantly delays the onset of wear so Raptor cutters are able to drill more footage before a wearflat is formed. When a wearflat is finally generated, the two diamond lips that result ensure that the cutter stays sharp so that the bit continues to drill efficiently, at a high rate of penetration.
Because Raptor cutters are more heat resistant, higher RPM can used in abrasive formations. This reduces or eliminates damaging torsional vibrations such as stick-slip. In field tests in the US Rockies, Raptor-equipped bits on average drilled 56% faster and 94% further than the best offsets.

WELLBORE CONSTRUCTION, INDIVIDUAL EQUIPMENT: FLOTHRU RESERVOIR DRILL-IN FLUID
M-I SWACO

Flow hydrocarbons and resist water invasion

The FloThru Reservoir Drill-In Fluid (RDF) system employs hydrophobic components that produce organophillic channels through the filter cake. The channels control the influx of water filtrate during drilling and completion operations while providing a clear avenue for the production of hydrocarbons. The resulting filter cake has very low permeability to water, but a much higher permeability to oil. As a result, FloThru eliminates the time and costs associated with using chemical breakers to clean up the filter cake.
Active drilled solids do not have an impact on the character of the filter cake. In a conventional water-based RDF, active drilled solids can increase the cohesive nature of the filter cake, requiring substantially more pressure to initiate flow.
FloThru uses a proprietary hydrophobic carbonate component combined with a hydrophobic starch to control fluid loss. These hydrophobic materials create organophillic pathways in the FloThru filter cake. Their filter-cake building characteristics provide a low permeability barrier to water to prevent high infiltration. These same organophillic channels overcome the adhesive nature of conventional water-based RDF filter cakes by providing increased transmissibility of hydrocarbons at low drawdown pressure, eliminating the need for chemical breakers.
FloThru is ideal for open-hole gravel packs, expandable screens, standalone completions or any open-hole completion application where the filter cake becomes trapped or difficult to treat.

WELLBORE CONSTRUCTION, SYSTEM: CONTINUOUS CIRCULATION SYSTEM
NATIONAL OILWELL VARCO

Continuous fluid flow while tripping pipe

The Continuous Circulation System (CCS) encloses the tool joint to be disconnected in a pressure chamber, which allows drilling fluid to flow down the drill string as the CCS disconnects the tool joint. The upper tubular is withdrawn and a set of blind rams separates the CCS into two chambers. The upper chamber is depressurized, which allows the top drive sub to withdraw and acquire a new tubular. The new tubular is inserted, brought up to pressure and connected to the drill string while drilling-fluid flow down the drill string remains steady.
Steady downhole pressure enabled by the CCS provides greatly reduced risk of lost circulation; formation fracturing; kicks; differential sticking; stuck bits or BHAs; easier navigation of narrow pore pressure or frac pressure gaps; longer drilled sections prior to casing; much longer laterals because of continuous cuttings transport; steady density, temperature and flow of returning mud and cuttings; and easier dual-density drilling. Safety is also increased because connection kicks are avoided.
Underbalanced drilling can restart immediately after each tool joint connection because circulation is continuously stable. There is no accumulated gas, and downhole pressure is steady. For re-entering depleted wells, the CCS provides a steady Equivalent Circulating Density (ECD), which is essential with through-tubing rotary drilling where the annulus is tight and the ECDs are high.

FACILITIES, SYSTEM: VSD TECHNOLOGY FOR FACILITY SOLUTIONS
SCHLUMBERGER

Low-voltage VSD reduces costs

Schlumberger's variable speed
drive (VSD) technology enables innovative electrical power distribution architecture, saving operators substantial weight and cost in topside equipment when deploying electric submersible pumps (ESPs), particularly when tying back remote production wells on unmanned minimum facility wellhead platforms.
This VSD application and facility design results in the elimination of the topside equipment listed below, which in turn eliminates costs and enables smaller platforms for both the main production facility and the remote wells.
Eliminated equipment includes:
• Offshore module and associated heating/ventilation/air conditioning (HVAC) and pressurization system for switchgear in hazardous areas local to the satellite wellheads;
• Offshore module and associated HVAC on main platform to protect switchgear from tropical climate;
• Line side harmonic filters, which in this case would require a large and heavy enclosure; and
• Additional space for load-side sinewave filters.
This solution is key in converting mature fields from gas lift to ESP in West Africa and elsewhere in the world where there are numerous unmanned platforms that do not have power generation and are hazardous area-classified. ESPs can be retrofitted to existing platforms cost-effectively, thereby extending the life of fields by increasing reservoir recovery beyond the life and limitations
of gas lift. This approach was
used for the electrical power
distribution architecture for the Morsa West field development operated by Sonangol, offshore Angola.

COMPLETIONS, INDIVIDUAL EQUIPMENT: SWELLPACKER
EASYWELL

A packer with no moving parts

Swellpacker swells and seals the annulus around a pipe in cased and open holes. It is based on the swelling properties of rubber in hydrocarbons. Swellpacker's thermodynamic absorption allows continuous expansion. It has a simple design, with no moving parts and low running friction. Installation requires no wash pipe, pumping or specialist expertise.
Swellpacker comes in many different versions and is compatible with oil-based and water-based mud. It can be used in pressures up to 9,000 psi and temperatures up to 400°F (204°C). Swellpacker's design enables spliceless cable feed-throughs for use in intelligent completions.
Swellpackers are used in a wide range of applications including cementing and perforating replacement, water and gas isolation in gravel-pack operations, open and closed-hole straddles, and isolation in intelligent completions.
In commercial applications, Swellpacker has:
• Reduced well-construction costs as much as 30% by replacing cementing and perforating;
• Reduced high water cuts to zero; and
• Increased value-investment ratio by 50%.


COMPLETIONS, SYSTEM: STIMWATCH STIMULATION MONITORING SERVICE
HALLIBURTON

Visualize stimulations in real time

Fluid placement is critical to the success of a stimulation treatment, whether it is wellbore cleanout, matrix stimulation or hydraulic fracturing. Previous methods of fluid-placement evaluation have been qualitative and post-treatment.
Using the StimWatch Stimulation Monitoring Service, a stimulation treatment can be "watched" as it progresses downhole. Real-time visualization allows treatment modification during the job. In addition, a quantitative analysis of injection flow profile is provided. This is valuable for future treatment designs.
The StimWatch Service starts with wellbore temperature profile data obtained with the company's fiber-optic distributed temperature monitoring system. Temperature data are converted into downhole flow rate profiles with a proprietary analysis tool. Quantitative indication of fluid distribution across the interval being stimulated is obtained without the need for shut-in periods or extensive preconditioning of the well bore. The fiber-optic cable can be temporarily conveyed via capillary tube, braided wireline cable or with coiled tubing. This allows operators to monitor stimulation treatments in real time on nearly every well, without the preplanning required in permanent fiber optic installations.
Collecting complete wellbore temperature profiles during the placement of stimulation and diversion fluids has opened up new possibilities for understanding and modifying matrix stimulation treatments.

PRODUCTION, INDIVIDUAL EQUIPMENT: FIBERFRAC
SCHLUMBERGER

Fibers enhance proppant placement

A Williston Basin operator drilling long laterals into the Bakken shale gets better production with a higher load recovery after using Schlumberger's FiberFRAC fluid technology.
Fibers in the frac fluid provide a mechanical aid to transport, suspend and place proppant in fractures by decoupling proppant transport from the viscosity of the fluid. That allows the engineer to tailor fluid properties to the reservoir rather than its ability to carry proppant.
In Headington Oil Co.'s case, the company drilled 5,000-ft to 8,000-ft (1,525-m to 2,440-m) laterals into the naturally fractured shale with permeability of .1 mD to .9 mD and 9% average porosity. The fracture design on offset wells called for five to seven fracturing stages in each lateral, but the crosslinked fracturing fluid was breaking down before it could properly place proppant.
Bottomhole temperatures reached 240°F (115°C), and the company used a 35-ppt borate crosslinked guar as the fracturing fluid. The operator wanted a stimulation program that would maximize fracture conductivity to improve flows from the fractures.
The company used FiberFRAC fluid for its enhanced proppant delivery properties. The fiber-based system allowed the company to reduce polymer concentraton by 43%, from 35 ppt to 20 ppt. Because less polymer was used, more of the propped fracture was able to contribute to production, giving the company a longer effective fracture half-length.
After using FiberFRAC, the company got improved transport, suspension and placement of proppant with no proppant settling after 4 hours.
It got 43% load recovery, compared with 15% for offsets, and brought in a 60% increase in oil production compared with offset wells.
The best use of the FiberFRAC system is in low permeability environments with temperatures between 150°F and 400°F (65°C and 204°C).

PRODUCTION, SYSTEMS: SURFACE CONTROLS FOR INTELLIGENT WELL
BAKER OIL TOOLS

Automated surface controls optimize intelligent wells

A touch-screen-controlled personal computer dictates instructions to a programmable logic controller to get maximum performance from downhole chokes in Baker Oil Tools' InForce intelligent well system with an automated surface control system.
Instructions from the computer remotely control hydraulically powered adjustable downhole chokes to selectively control production or injection operations in individual zones while downhole instruments provide real-time monitoring for pressure, temperature and single-phase flow through a surface data acquisition system.
Used in six electric submersible pump wells in South America, the system allowed the operator to commingle production by allocating flows from two zones. The system had one HCM-A downhole choke on the upper zone and a shrouded HCM-A choke on the deeper zone with a single-phase flowmeter measuring production only from the lower zone and gauges monitoring pressure and temperature from both zones. One computer controls flows from two wells and a second will control flows from the other four.
The wells displayed increased production, lower water cut, maximum pump drawdown without allowing pressure to drop below bubble point and fewer interventions than similar conventionally controlled wells.
According to the company, production from the most recent well, in some instances, has more than doubled in direct reaction to the monitoring and control capability from the system.
The system allows the operator to shift the position of the choke to any position while the well is producing when a conventional well would have to halt production for intervention.
The system should allow the operator to improve efficiency in controlling and monitoring production or injection wells, optimize production, extend well life and ultimate recoveries, and improve overall profitability.
Chokes operate with 10,000 psi of hydraulic fluid pressure, and the choke has six pre-determined setting in addition to fully open and fully closed.

REMEDIATION, SYSTEM: INFLATABLE SERVICE PACKER
BAKER OIL TOOLS

High-expansion tool takes on large-diameter wells

When an operator needs to isolate a large-diameter well bore in a wide range of cased- and openhole applications in deepwater or heavy-duty situations, it may be time to call in the Blue Whale.
Baker Oil Tools' Blue Whale Inflatable Service Packer replaces traditional equipment deployed in large-diameter work strings with a single tool that reduces rig time, storage requirements and transportation costs.
The tool can work as a retrievable or permanent bridge plug, a permanent cement retainer, a retrievable service packer, or a casing spear.
A major operator in the Gulf of Mexico used the tool to complete a job in 2 days that conventional equipment couldn't accomplish in 2 weeks. The company had disconnected a riser to move off location ahead of an approaching storm. When the storm had passed, the operator moved back in to reconnect the riser and continue operations. It tried to reconnect for 2 weeks using conventional tools, but strong currents thwarted attempts to align the riser for connection.
Switching tactics, the company set a Blue Whale Inflatable Service Packer at the bottom of the riser at 5,100 ft (1,555.5 m) in a temperature of 41°F (5°C) and inflated the packer with water. After releasing the disconnect, it replaced sea water in the riser with 16 lb/gallon mud to add weight to the riser and allow it to resist the strong current. After 2 days, it was able to re-connect the riser and retrieve the packer.
The Blue Whale uses a 103.25-in.-long inflatable element for a longer seal area with increased pressure. It expands more than 200%. A bottom guide and shear-pinned bottom sub prevent swabbing during run-in.
The packer sets without tubing weight. It has a 300,000-lb tool tensile rate and a 5,000-ft/lb (1,525-m/lb) torque rating.


REMEDIATION, SYSTEM: SMART INTERVENTION SYSTEM
BAKER OIL TOOLS

Downhole system raises efficiency of intervention

The Smart Intervention System allows operators to examine true, real-time downhole parameters to make better-informed scientific and logical management decisions to immediately optimize intervention activities in wells.
The system includes the traditional tools - retrievable bridge tools, shifting tools, mills, overshots and whipstocks - and adds a short, modular sensor integrated into the bottomhole assembly to gather pull-on-tool, weight-on-mill, torque, RPM, bending moment, vibration, and annular and bore pressures for display at the surface.
An operator used the Baker Oil Tools Smart Intervention Performance sub in a deepwater offshore well in the Gulf of Mexico to show downhole conditions that couldn't be seen at the surface. Real-time analysis allowed the operator to avoid future window access problems. When the system detected a potentially serious early jump-off problem, the operator lowered weight-on-bit to mitigate the threat.
The system later measured the dogleg severity of the window, so the operator could confidently run the rotary steerable drilling bottomhole assembly and set expandable drilling liner through the window with confidence.
Overall, the company minimized non-productive time in window milling and cutter damage and accomplished an early exit. In addition, an expert team in the operator's real-time operating center was able to witness the entire milling operation and collect the data to optimize future tool and job designs.
The system includes the smart Intervention Performance sub with 14 sensors and electronics for digital signal processing in 31¼8-, 43¼4- and 81¼4-in. sizes. The tool is 9 ft (2.7 m) long and rated for operations at temperatures to 300°F (148.7°C) and 25,000 psi. On the surface, a rig-floor monitor screen provides a visual display of the downhole measurements.
According to the company, the improvements in performance and process controls reduces uncertainty, non-productive time and flat-time costs.