Piazza, Ralph (Petrobras) | Vieira, Alexandre (Petrobras) | Sacorague, Luiz Alexandre (Petrobras) | Jones, Christopher (Halliburton) | Dai, Bin (Halliburton) | Price, Jimmy (Halliburton) | Pearl, Megan (Halliburton) | Aguiar, Helen (Halliburton)
This paper presents a new optical sensor configuration using a multivariate optical computation (MOC) platform in order to enhance chemical analysis during formation tester logging operations. The platform allows access up to the mid-infrared (λ ~ 3.5 microns) optical region, which has previously not been accessible for in-situ real-time chemical measurements in a petroleum well environment. The new technique has been used in the field for the analysis of carbon dioxide and synthetic drilling fluid components such as olefins.
MOC is a technique that uses an integrated computational sensor to perform an analog dot product regression calculation on spectroscopic data, optically, rather than by electronic digital means. Historically, a dot product regression applied to spectroscopic data requires both a spectrometer and a digital computer in order to perform a chemical analysis. MOC sensors require neither and because the key sensor component, the multivariate optical element (MOE), is a stable temperature robust solid-state element, the technique is well suited for downhole petroleum environments. A new dual-core configuration using two MOEs designed to work in parallel enhances the sensitivity of the measurement enabling a mid-infrared analysis.
Spectroscopic measurements were performed on 32 base oils that were reconstituted to reservoir compositions over a wide temperature and pressure range up to 350°F and 20,000 psi for a total of 12 combinations for each base oil. Live gas compositions (i.e. reservoir conditions) were achieved by adding multiple methane, ethane, propane, and carbon dioxide charges to each base fluid. The reconstituted petroleum fluids were further mixed with olefin-based synthetic drilling fluid (SDF). This rigorous experimental design data therefore allowed for solid state MOEs to be designed to operate under the same reservoir conditions. Laboratory validation showed measurement accuracy of +/-0.43 wt% for a range of 0 to 16 wt% CO2 and +/-0.4% from 0 to 10 wt% SDF. A wireline formation tester optical section was modified with the MOC dual-core configuration to enable the mid infrared detection of both carbon dioxide and olefins. This formation tester was then deployed in five wells collecting seven samples from various locations. The downhole SDF and carbon dioxide measurements were subsequently found to be in good agreement with laboratory analysis with field results for valid pumpouts showing an accuracy of 0.5 wt% CO2 and 1.0 wt% olefins cross a range of 1.2 to 22 wt% CO2 and 1.4 to 9.7 wt% SDF.
Carbon dioxide is an important component of petroleum whose presence and concentration affects completion options, surface facilities, and flow assurance, which thereby affects operational costs of petroleum production. Olefins are a primary component of synthetic drilling fluid (SDF), although other mid-infrared active components such as esters, ketones, alcohols, and amines also can be present. High concentrations of SDF in openhole formation tester samples lower the quality of laboratory phase behavior analysis and thereby force greater monetary risk in development of assets, especially when conducting reservoir production simulations. Therefore, it is important to monitor both components during formation tester sampling operations.
Golovko, Julia (Halliburton) | Jones, Christopher (Halliburton) | Dai, Bin (Halliburton) | Pelletier, Michael (Halliburton) | Gascooke, Darren (Halliburton) | Olapade, Peter (Halliburton) | Van Zuilekom, Anthony (Halliburton)
Phase behavior characterization (PVT) and geochemical compositional analysis of petroleum samples play a crucial role in the reservoir evaluation process to help determine producible reserves and the best production strategy. Openhole samples are the most valuable types of samples for PVT and geochemical analysis. Unfortunately, traditional openhole sampling methods are costly and limited to ten to twenty samples, thereby restricting the scope of characterization in a well section. This study summarizes a new microsampling technique for logging while drilling (LWD) and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir fluid compositional grading, and reservoir compartmentalization assessment. This microscale approach allows fast analysis with a field or near-field deployment of the analytical tool, providing fast turnaround time for analysis. The results inform planning for wireline sample retrieval, if necessary.
The microsampler used in the downhole tool is capable of collecting reservoir fluid in small quantities, suitable for compositional analysis. Because of its small size, the microsampler can gather multiple fluids at various reservoir depths, while PVT sampling requires larger volumes and has more constraints. However, when used in combination with conventional PVT-grade samples, the microsamples can provide significant chemical profiling. The quantity of 40 microliters (
Recovery to surface of fluid samples collected at reservoir temperature and pressure allows for analysis with an automated gas chromatograph (GC) deployed in the field, providing reduced labor and rapid analysis. The unique injection chamber of the GC is designed with the injection port and valve configured to withstand pressure up to 5,000 psi, which is approximately five times higher than standard GC injection valves. This allows for injection of the microsample with a solvent carrier as a single-phase fluid so that analysis can provide composition and fluid properties, such as gas to oil ratio, without a flash. The GC has two detectors including a flame ionization detector (FID) for hydrocarbon components and thermal conductivity detector (TCD) for inorganic gas components, such as carbon dioxide, nitrogen, and hydrogen sulfide. The system can quantify hydrocarbon components from C1-C36 and perform contamination studies of oil samples with drilling fluids.
This study provides a new technique for reservoir engineers to characterize a reservoir completely, without limit to the number of acquired samples. In combination with conventional PVT samples, it is possible to extrapolate the PVT properties to all pump-out stations, and conduct a complete geochemical profile of the reservoir.
Optical fiber flatpacks, which are cable-reinforced plastic-encased fiber bundles used for local temperature and acoustic measurements, can be stressed when near a perforating gun. The fiber itself is floated in metal tubes with gel. Understanding the behavior under severe shock causes the use of potential mitigation schemes. In this work, the flatpack containing optic fibers is simulated for survivability on the casing of a perforating gun system. Using a shock hydrocode in two-dimensions (2D), a flatpack is simulated on the 5 1/2-in. casing of a 3 3/8-in. gun with a 21-g shaped charge. Effects of concrete encasement, clamps, and off-angle shots are considered. The view is in the plane of one shaped charge.
Quantitative results include pressure temporal profiles, velocity profiles, and g acceleration at the fibers. Pressure at the flatpack peak is in the hundreds to thousands of psi, and accelerations peak in the hundreds to thousands of g. Unconfined flatpacks tend to launch from the casing, while confined flatpacks tend to oscillate at their location. Pressure contour models show the shaped charge breaking into multiple pressure pulses. The primary shocks are in front of and behind the charge. Secondary pulses occur off-axis near the base of the charge and from the jet bow shock near the top of the charge. Overall comparative simulation results indicate optimum flatpack location and configuration. Novel mitigation schemes are identified and simulated. A fiber-optic flatpack has been simulated in a zero- degree loaded gun for the first time; this information helped with understanding survivability against shaped charge shocks.
Directional drilling for hydrocarbon exploration has been challenged to become more cost-effective and consistent with fast-growing drilling operations for both offshore and onshore production areas. Autonomous directional drilling provides a solution to these challenges by providing repeatable drilling decisions for accurate well placement, improved borehole quality, and flexibility to adapt smoothly to new technologies for drilling tools and sensors. This work proposes a model predictive control (MPC)-based approach for trajectory tracking in autonomous drilling. Given a well plan, bottomhole assembly (BHA) configuration, and operational drilling parameters, the optimal control problem is formulated to determine steering commands (i.e., tool face and steering ratio) necessary to achieve drilling objectives while satisfying operational constraints. The proposed control method was recently tested and validated during multiple field trials in various drilling basins on two-and three-dimensional (2D and 3D) well plans for both rotary steerable systems (RSS) and mud motors. Multiple curve sections were drilled successfully with automated steering decisions, generating smooth wellbores and maintaining proximity with the given well plan.
Unal, Ebru (University of Houston) | Rezaei, Ali (University of Houston) | Siddiqui, Fahd (University of Houston) | Likrama, Fatmir (Halliburton) | Soliman, M. (University of Houston) | Dindoruk, Birol (Shell International Exploration and Production, Inc.)
In the last decade, technical advancements have greatly improved the design and execution efficiency of well completions, leading to improved recovery from unconventional reservoirs. However, analyzing fracture diagnostic tests in unconventional plays are still challenging due to high uncertainty in predictive capabilities in the context of fracture dynamics during treatment. The main objective of this study is to identify fracture behavior during injection and pressure fall-off periods in hydraulic fracturing treatments and diagnostic fracture injection tests (DFIT), respectively.
In this study, discrete wavelet transformation (DWT) was used to analyze real field injection and fall-off data in the wavelet domain. The analyzed data are from multi-stage hydraulic fracturing operations and DFIT in unconventional horizontal wells. DWT coefficients reveal very crucial information related to the nature of the events within recorded signals; they also reveal various patterns that are hard to recognize otherwise. The high-frequency components of the pressure and rate signals (detail coefficients) that are calculated by the wavelet transformation determine localization and separation of various events. We compared the identified events for injection and fall-off periods with moving reference point (MRP) and G-function analysis, respectively.
The main advantage of our proposed approach is that it is based on real-time data and does not require any assumptions related to existing or created fractures. Also, it is very sensitive to physical changes in the system; thus, it reveals hidden information related to those changes. Consequently, the energy of detail coefficients represents several events at different frequencies. We used pseudo-frequency of wavelet coefficients as a diagnostic tool for an accurate comparison of fracture propagation and fracture closure events to determine similarities and differences between them. For example, the signal energy of detail coefficients from the wavelet transformation of hydraulic fracturing data demonstrates abrupt frequency changes during dilation or fracture height growth during fracture propagation. Therefore, we were able to identify those events by energy density analysis in both time and pseudo-frequency domains in an objective manner, which otherwise was not possible with conventional methodologies such as G- function derivative analysis.
This paper details the successful methodology for effective implementation of a new fracture diagnostic technique for fracturing operations or DFITs in unconventional horizontal wells. This new fracture diagnostic method does not require any reservoir or fracture pre-assumptions; it mainly relies on the pressure behavior, which is a result of various events at different frequencies. Pressure fall-off behavior of a DFIT gives essential information related to closure event of the created mini-fracture. Identification of these events at different pseudo-frequency ranges improves the understanding of the dynamic fracture behavior also the characteristics of the reservoir. Unlike many other diagnostic techniques, this data-driven approach requires minimum input/data for analysis. This approach also lends itself to real-time application quite easily.
A new electronic sliding sleeve has been developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug and perf techniques. This battery-powered electronic sliding sleeve provides the operational efficiency of sliding sleeves in an unlimited number of zones. The firmware, electrohydraulic lock, and electronics package in this new sliding sleeve help enable a range of operational functions for use in hydraulic fracturing.
Traditional sliding sleeves use a series of progressively sized balls that shift sleeves by landing on progressively sized baffles. An electronic sliding sleeve creates a monobore construction with the same inside diameter bore in each sleeve and helps enable treating of an unlimited number of zones. The electronics in the sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools. The firmware and electronic package enable a modular approach to electronic sleeve design. Therefore, one frac sleeve chassis design can be used for many of the different types of sleeve tools in the well completion, and the firmware that drives the electronics is modified for each respective type of tool.
Using combinations of the electrohydraulic lock, electronics package, and firmware can enable the design of all the tools necessary to complete a wellbore. The standard firmware, used for a single point entry sleeve, operates by counting the correct number of frac balls. When the correct count is reached, the electrohydraulic lock is released, enabling sleeve movement or zonal isolation deployment. A modification can be made to the firmware to have the tool actuate on the next count, rather than the initial count, and delay the time at which the electrohydraulic lock is released. This type of architecture lends itself to the design of multi-entry sleeves. The sensor can also be eliminated by using the delay feature in the firmware of the electrohydraulic lock, programmed in weeks. This type of architecture also helps enable the design of a toe sleeve.
Having the ability to implement slight modifications to the components that make up the sliding sleeve enables design flexibility and modularity for all sleeve type tools necessary to complete a wellbore. This type of system architecture helps decrease operator risk and ease design constraints while performing multiple functions downhole.
Nguyen, Dzu (BP) | Macleod, Innis (BP) | Taylor, Donald (BP) | Murray, Laurence (BP) | Zavyalov, Denis (BP) | Booth, Dave (Fircroft Consultant, former BP) | Robertson, Neil (Halliburton) | Smith, Robert (Halliburton) | Joubran, Jonathon (Halliburton) | Allen, Clifford (Halliburton) | Shafei, Sharil Mohd (Halliburton)
The multiple zone water injection project (MZWIP) was initiated to deliver the following key objectives: deliver zonal injection with conformance control and reliable sand management across the major layered sands of the Balakhany unconsolidated reservoirs in the BP operated Azeri-Chirag-Gunashli (ACG) fields in Azerbaijan sector of the Caspian Sea.
Three years after MZWIP implementation, six wells with a total of 14 zones are injecting at required rates with zonal rate live-reporting. To achieve this multizone injection facility, the requirement for a standard ACG sand-control injector design was discounted and a non-standard sand management control technique developed using a cased & perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world's first 10kpsi three-zone inline variable-choke DHFC wells with distributed temperature sensors (DTS) across all target injection zones.
The choking DHFC provides flexibility in operations and delivers the right rates to the right zones. The DTS provides conformance surveillance, fracture assessment, caprock integrity and sand ingress monitoring capability. A customized topside logic control system provides an automatic shutin of interval control valves (ICVs) during planned or unplanned shutins to stop crossflow and sand ingress and is the primary method of effectively managing sanded annuli.
The development of this MZWI solution has significantly changed the Balakhany development plan and has been quickly expanded across five ACG platforms. Accessing 2nd and 3rd zones in the same wellbore, this C&P DHFC well design is accelerating major oil volumes and will significantly reduce future development costs, maximizing wellbore utility in a slot-constrained platform.
Banack, Ben (Halliburton) | Burke, Lyle H. (Devon Canada Corporation) | Booy, Daniel (C-FER Technologies 1999 Inc.) | Chineme, Emeka (Cenovus Energy) | Lastiwka, Marty (Suncor Energy) | Gaviria, Fernando (Suncor Energy) | Ortiz, Julian D. (ConocoPhillips Canada) | Sanmiguel, Javier (Devon Canada Corporation) | Dewji, Ayshnoor (Halliburton)
It is becoming common to install inflow control devices (ICDs) along steam-assisted gravity drainage (SAGD) production liners to enhance temperature conformance and accelerate depletion. Additionally, some operators advocate the installation of similar outflow control devices (OCDs) along the injection well of the SAGD well pair. Collectively, these inflow and outflow devices are often referred to as FCDs. Industry adoption of flow control devices (FCDs) has increased, and several devices are commercially available for use in SAGD.
In an effort to optimize FCD design and selection, a joint industry partnership (JIP) was formed (
Fiber-optic-based instrumentation was deployed within FCD-equipped wells using permanently installed coiled tubing. Well architecture design changes to a typical completion were not required because fiber-optic sensors are used for most non-FCD wells to collect distributed temperature sensing (DTS) data. Although DTS is a common tool for optimizing SAGD production, it has certain limitations; specifically, temperature changes along production wells do not typically allow a detailed definition or quantification of the inflow distribution along the wellbore.
In addition to DTS, distributed acoustic sensing (DAS) was periodically performed on the FCD wells. DAS logging of SAGD producers has several potential uses, including flow profiling, steam breakthrough and/or noncondensable gas (NCG) detection, multiphase flow characterization, electric submersible pump (ESP) performance, completion failure analysis, and four-dimensional seismic analysis. Although FCD characterization with DAS appears promising, a knowledge gap exists as to how to move beyond qualitative analysis to more quantitative analysis of FCD performance and the lateral emulsion inflow distribution. Pending satisfactory results, DAS logging on active wells can potentially be completed to accelerate improvements of SAGD FCD performance and design as well as increase the efficiency of SAGD recovery through improved steam/oil ratio (SOR) and an associated reduction in greenhouse gases.
This paper describes piloting the collection and analysis of DTS and DAS data to help improve understanding of SAGD inflow distribution. Logs were performed on multiple wells during stable and transient flowing conditions. Early surveillance demonstrated suitability and limitations of fiber-optic-based logging to validate FCD performance in active wells. In addition to field logging, acoustic recording using JIP flow loop testing was completed with accelerometers, geophones, and fiber-optic cables during FCD characterization. The goal was to cross reference the acquired acoustic signals for quantification of flow at devices and validation of performance. An overview of the JIP flow loop FCD acoustic characterization program is described.
Successfully spotting an Off-Bottom Cement Plug (OBCP) has been problematic in the oilfield for decades. The use of high viscosity support spacers below the cement plug has been an attractive method to support the cement. These isolation spacers have traditionally been formulated with either biopolymers or bentonitic clays, but they too often fail to support the cement plug due to inadequate viscosity or poor placement. The result is that the cement slumps below the desired location in the wellbore, requiring some remedial action such as spotting an additional spacer and OBCP. One response to this challenge has been the use of a packer to support the plug, but this entails the additional cost of the packer plus the rig time required to place it. A better method was needed to increase OBCP success while reducing costs. A new isolation spacer technology was adapted to meet this challenge, and the resulting field applications are described in this paper. Developmental lab testing will be detailed along with an initial trial well where the spacer was used to isolate a retrievable packer from workover debris. After success there, the same spacer technology was used to successfully support an OBCP on a rigless well abandonment.
On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse.
A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with "skip-and-ship" operations were minimized significantly.
The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore.
Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No "wait on weather" time (rig day rate = USD 300,000) No dedicated vessels for transport No quayside cuttings handling No trucking to treatment and disposal facilities
No "wait on weather" time (rig day rate = USD 300,000)
No dedicated vessels for transport
No quayside cuttings handling
No trucking to treatment and disposal facilities
Safety and environmental benefits add the following value: Reduced manual handling of skips Reduced crane lifts Base oil reuse Liability for waste ends at rigsite
Reduced manual handling of skips
Reduced crane lifts
Base oil reuse
Liability for waste ends at rigsite