Antle, Ryan (Baker Hughes, a GE Company)
Computer vision (CV) techniques were applied to X-ray computed tomographic (CT) images of reservoir cores to evaluate their potential for rapidly identifying fractures and other lithologic/geologic characteristics. The analyses utilized feature-labeled CT cross sectional images, themselves distributed submillimeter voxels of density- and atomic number-sensitive CT Numbers, as inputs to a Fully Convolutional Neural Network (FCN) for semantic segmentation of reservoir core features. In FCN, an image is interrogated using a series of sliding windows at various scales to create weighted filters to reduce error between classes in training images. These networks of filter layers were used to assign probabilities of classes, which were upscaled back to the original image dimensions resulting in probabilistic class assignments onto each pixel. FCN model accuracy, defined by its ability to replicate manually-assigned labels in the raw (unannotated) training image stack, was at least 80% and generally improved with the size of the training set. Once the labels were assigned, the underlying feature frequency, orientation, and size were measured in 3D volume reconstructions using algorithms modified from standard image analysis software. This method allowed users to endow a classification model with subject matter knowledge for further, autonomous label prediction. Thus, while initial image annotation was labor intensive, subsequent images were rapidly classified once the model was built. The classified labels were analyzed for abundance, orientation, and size of fractures were calculated to characterize spatial information of these features. FCN combined with fracture labeling improved knowledge capture and automation of fracture identification. Models trained by high quality 3D datasets can greatly reduce the time needed to describe subsequent core. The method demonstrated is not limited to fractures, other lithologic/geologic features could be trained using the same method, which may result in additional efficiencies.
Yang, Junjie (Baker Hughes, a GE Company) | Karam, Pierre (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Hustak, Crystal (Baker Hughes, a GE Company) | Doherty, James (Riley Exploration – Permian, LLC) | Allen, Carmen (Riley Exploration – Permian, LLC)
As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.
Karam, Pierre (Baker Hughes, a GE Company) | Yang, Junjie (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Stephenson, Tim (Baker Hughes, a GE Company) | An, Xiaoxuan (Baker Hughes, a GE Company) | Jung, Chimok (SK E&P Operations America) | Jun, Jongyoung (SK E&P Operations America) | Lee, Hyungseok (SK E&P Operations America)
Sooner Trend Anadarko Canadian Kingfisher, also known as STACK, is a booming unconventional oil play in North America. As one of the main features that makes the asset profitable, multiple targeting benches raise a challenge of optimization. Well-developed natural fracture system brings in another level of complexity to estimate well spacing. This study introduces an integrated workflow to better understand the fluid flow mechanism in the reservoir and optimize development strategy.
From borehole image log, natural fracture orientation and density was interpreted and statistically populated into geologic model along with petrophysical properties. To account for productivity enhancement due to natural fractures, enhanced permeability was embedded into the simulation model according to the distribution of discrete fracture network. After being history matched, the reservoir model was used to test the sensitivity on well spacing, landing zone and hydraulic fracturing pump schedule. Both infill drilling program and green field development scenarios were tested and compared to optimize our field development study.
Production history match indicates that natural fractures serve as fluid flow conduit and contribute significantly to the production in Osage. Pressure transient observation shows a similar reservoir behavior in the Osage as opposed to the Woodford. Multiple wells experience productivity reduction over longer production history, indicating near-field damage (such as scaling) and/or far-field damage (such as fracture closure). Introduction of skin factor and pressure dependent permeability captured the trend on productivity behavior in the history match. In addition, the simulation study shed light on the hydraulic fracture geometry that provides direct insight on well spacing and landing zone analyses. Results from the infill drilling program show that staggered design with 3 Osage and 4 Woodford wells per section yields the higher oil recovery. However, using the greenfield sensitivities, and depending on the pumping schedule, hydraulic fractures from Woodford wells show upward growth, draining both formations effectively even without Osage wells.
This study provides valuable information about the development strategy in STACK unconventional resources, particularly for scenarios with natural fracture system and multiple targeting zones. The simulation workflow considers well interference in both horizontal and vertical directions simultaneously to optimize oil recovery and reduce operational cost.
Hurlburt, Maurice (Athabasca Oil Corp.) | Quintero, Jonathan (Baker Hughes, a GE Company) | Bradshaw, Robert (Baker Hughes, a GE Company) | Belloso, Andres (Baker Hughes, a GE Company) | Cripps, Evan (Baker Hughes, a GE Company) | Blakney, Donya (Baker Hughes, a GE Company) | Glass, Darnell (Baker Hughes, a GE Company)
A Canadian oil & gas operator has been setting new benchmarks drilling the vertical and tangent section of Montney horizontal wells in the Placid field of Northern Alberta. Initially, the operator drilled vertical wells to kick off point (KOP) with polycrystalline diamond compacts (PDC) and conventional mud motors. As a result of increasing well density, however, the well plans consistently required a 15° to 30° tangent section. With PDC drilling, toolface and build up rates were problematic and the sliding rate of penetration (ROP) was slow.
A Rotary Steerable System (RSS) was introduced, but despite the improved performance, the technology came at a premium cost and the severity of drilling dysfunctions generated an increase in tool failures. With falling oil prices, a more cost effective solution was required.
Hybrid bit technology, which combines the cutting mechanism of both fixed cutter and roller-cone bits, has been extensively utilized in Canada to drill build sections, providing outstanding results. They have not, however, been commonly used to drill the vertical (drill-out) and tangent sections. The operator combined a state-of-the-art hybrid bit with a mud motor to drill the interval with an 85% success rate. The combination of the hybrid bit and conventional motor, compared to PDC and RSS, resulted in a 30% cost savings to complete the interval.
The present case study outlines how hybrid bit technology development, driven by field data in a continuous improvement cycle, identifies performance opportunities, which have a significant impact on drilling time and cost savings in drill out sections. The overall objective of this current case study is to highlight the results and lessons learned throughout the implementation process.
A new method has been developed to differentiate and quantify the amount of primary amines through a simple chemical process. Colored cyclic adduct compounds are formed by reaction of selective chemicals with primary amine. This adduct formation is preferential to the primary amine, even in the presence of a mixture of secondary and tertiary amines. The adduct shows selective enhanced fluorescence emission at 475-nm wavelength under specific excitation with 420 nm. Due to enhanced fluorescence activity, quantification becomes possible, even below a 1-ppm concentration of specific primary amine. A chemical matrix, formulated with the mixture of different concentrations of primary, secondary and tertiary amines, helps to differentiate and quantify primary amines present in the mixture, even at lower concentrations. This method is validated under synthetic field brine conditions to detect and quantify primary amines towards field applications.
As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs.
In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months; Treating individual wells with tagged versions of the same scale inhibitor chemical; Treating individual wells with different scale inhibitors.
Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;
Treating individual wells with tagged versions of the same scale inhibitor chemical;
Treating individual wells with different scale inhibitors.
Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required.
Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers.
This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.
Rodgers, Patrick (Baker Hughes, a GE Company) | Lundy, Brian (Baker Hughes, a GE Company) | Ramachandran, Sunder (Baker Hughes, a GE Company) | Ott, James (Baker Hughes, a GE Company) | Poelker, David (Baker Hughes, a GE Company) | Lee, Dong (Baker Hughes, a GE Company) | Stevens, Corey (Baker Hughes, a GE Company) | Bounds, Christopher (Baker Hughes, a GE Company) | Sullivan, Matthew (Baker Hughes, a GE Company)
Operators producing hydrocarbons from conventional and unconventional wells often encounter interconnected production-related challenges that exacerbate one another. Challenges during production include the corrosion of steel caused by acid gases, as well as the precipitation and accumulation of iron sulfide, calcium carbonate scale, and barium sulfate scale. The accumulation of solids on pipe walls can facilitate under-deposit corrosion and plugging. Each of these issues can lead to failures and costly workovers. To address these issues, current treatment approaches require multiple chemical applications, frequent batch treatments, mechanical intervention, or a combination of approaches. In certain scenarios, these approaches can be impractical, ineffective, and/or uneconomical. The objective of this study was to develop a solution to overcome the aforementioned production challenges simultaneously and continuously with a single chemical application. The design strategy was to formulate chemicals that included a variety of chemistries to inhibit multiple corrosion mechanisms, as well as an iron sulfide dissolver, and a scale inhibitor to inhibit the formation of calcium carbonate and barium sulfate scales. Laboratory tests were conducted to demonstrate that the formulations could function in the aforementioned areas. One formulation was then applied in the field under different production scenarios: oil wells equipped with either a gas lift mechanism or an electrical submersible pump. Data from those situations are presented to demonstrate the field performance of the new formulation. Compared to the benchmark chemical treatment efforts, application of the formulation improved or maintained similar corrosion control, reduced or eliminated the accumulation of iron sulfide solids in the well, and improved scale control in each of the production scenarios. This paper presents a viable option for effectively treating common production challenges simultaneously and with one chemical application, which is particularly useful when it is impractical or uneconomical to employ multiple chemical treatments.
Static jar tests are widely known and used in the oil and gas industry for quantitative screening and determining the minimum effective dose (MED) for scale inhibitors. However, when dealing with very low saturated brines, challenges are faced in the laboratory to replicate the same scaling environment found in the oilfield facilities and often brines have to be stressed in order to induce scaling in the laboratory tests. This paper proposes an efficient approach for quick chemical selection and recommendation for low scaling environments.
The method proposed has been developed and successfully applied for the selection and recommendation of scale inhibitors in low to mild saturated brines. This technique involves the combination of the standard static jar test with Scanning Electron Microscopy (SEM) and UV-Visible Spectrophotometry (UV/VIS).
The two case studies presented here shows two fields with low to mild barium sulphate (BaSO4) and calcium carbonate (CaCO3) scaling issues. This novel approach of has been used to screen and identify the best scale inhibitor in terms of cost effective peformance. Post-experimental analyses such as the Scanning Electron Microscope/Energy Dispersive X-Ray Diffraction Spectrometry (SEM/EDXS) permitted the investigation and assessment of the type of scale formed, and the mechanisms of inhibiton for each scale inhibitor chemistry tested.
This combined approach removed any discrepancies obtained by visual observations and/or Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) efficiency measurements. Furthermore, the UV-Visible Spectrophotometry was used in conjunction to the static SEM/EDXS method, in order to reassess the MED for the scale inhibitor candidates using the kinetic turbidity test (KTT) method. Results obtained from the KTT method complimented those from the combined static with ICP and SEM imaging, providing a quick understanding of the scale formation kinetics and inhibition efficiency.
To summarise, results have shown that different techniques can be used as a fast screening process for the MED using different scale inhibitors at low scaling regimes. Therefore, the static SEM and KTT methods are recommended as a thorough screening process for determining the optimum MED and selection of the best fit for purpose scale inhibitor. This opposes the conventional dynamic scale loop (DSL) approach, which would require severe alterations to the brine chemistry in order to get a scaling blank within a minimum 2-hour-period.
Scale inhibitor (SI) analysis is an extremely important part of scale management and, in recent years, much work has been done on the development of specialist scale inhibitor analysis techniques like Liquid Chromatography Mass Spectroscopy (LCMS) to push the boundaries of low level scale inhibitor detection. However, LCMS requires costly and complex instrumentation and there was therefore still a need for the development of other advanced techniques like fluorescence (F) and Time resolved Fluorescence (TRF) that can be used on site to provide near "on line" data.
Fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules like polyamines whereas the operation principle of TRF is based on interactions between lanthanide ions and various functional groups of polymer or phosphonate scale inhibitors.
Both techniques work individually or in combination and this provides a distinct advantage for multiple scale inhibitor analysis in produced brines that enable the design of packages of different products for specific field applications. In addition, TRF and fluorescence techniques offer the capability of on-site detection compared to the majority of scale inhibitor analysis techniques and other advanced methods like LC-MS.
The ability to detect both phosphonate and polymeric scale inhibitors at very low MIC (<1ppm) has the potential for significantly extending scale squeeze lifetimes. This has now also allowed highly efficient, F tagged polymers, to be used in field situations where scale squeezing was either stopped or the lifetime was significantly compromised because of the lack of confidence in the residuals analysis.
Specific field and theoretical examples from both sub-sea and conventional wells will be presented where the application of both advanced fluorescence and TRF techniques has shown significant improvements in scale management.
This paper will compare and contrast the pros, cons and limitations of both fluorescence and TRF techniques for both phosphonate and polymeric scale inhibitors. In addition, it will highlight examples where scale management significantly improves through the application of Fluorescence and/or TRF scale inhibitor analysis techniques in complex production scenarios.
Guo, Shusheng (CNOOC Ltd_Zhanjiang) | Gao, Yongde (CNOOC Ltd_Zhanjiang) | Gui, Feng (Baker Hughes, a GE Company) | Wang, Shanshan (Baker Hughes, a GE Company) | Bordoloi, Sanjeev (Baker Hughes, a GE Company) | Ong, See Hong (Baker Hughes, a GE Company) | Du, Chao (CNOOC Ltd_Zhanjiang) | Wang, Shiyue (CNOOC Ltd_Zhanjiang)
The drilling in Wushi Sag of the Beibu Gulf appears to be problematic with frequent pack-off, tight-hole and stuck-pipe events as well as kicks and losses occurring in different wells. It is of great importance to find out the main cause or causes of these problems so that proper methods and techniques can be utilized to mitigate the problems and reduce the drilling non-productive time (NPT).
A series of drilled wells were reviewed to identify the key wells to be used for the geomechanical modelling and to help with understanding the drilling problems. One of the outcomes of the detailed geomechanical analysis was the realization that the stresses and rock behaviors are mainly affected and controlled by the structures. Wushi Sag can be divided into four structural areas: subsag-steep slope in the south, central inverted structure area, north slope and strike-slip faulting belt in the west. As a consequence of the complex structures, the formation depth varies greatly while some formations are absent or incomplete in some wells due to the well-developed high-angled faults.
An outcome of the study was the understanding that formation pressures are different in every structural area and are controlled by structural location and burial depth. The main overpressure generating mechanism was found to be type-II fluid expansion caused by either hydrocarbon generation or thermal effects, which can be well correlated to the oil window threshold in the area. Under-compaction may also play a role in some cases, but the overpressure caused by this mechanism is usually low in magnitude. Rock properties vary across the Sag while wells are hard to correlate with each other in different structural areas. The stress conditions appear to be different in each area although the main stress regime is strike-slip with the strike-slip faulting belt in the west having the highest stress ratio.
Due to the complexity of the pressure distribution, lateral formation changes and different stress conditions, improper mud weights and casing designs were used in some earlier wells, which likely led to the types of drilling problems listed above. Wells with severe instability problems were generally drilled with lower mud weights compared to the wells with lesser problems. Wells with both pack-off/tight holes and fluid losses usually have surface or intermittent casing shoes set too shallow while not preparing for the steep pressure ramp in deeper formations. Based on the problem diagnostics and geomechanical analyses, recommendations were made to help with the drilling of future wells by mitigating drilling-related instability problems. A series of wells were drilled successfully following the recommendations with all the possible risks properly understood and mitigated.