Imbazi, Oyeintonbra (Shell Company in Nigeria) | Ugoh, Oluwatobi (Shell Company in Nigeria) | Okoloma, Emmanuel (Shell Company in Nigeria) | Osuagwu, Micheal (Shell Company in Nigeria) | Enyioko, Chigoziem (Halliburton) | Ighavini, Emmanuel (Halliburton) | Uzodinma, Chioma (Halliburton)
Well 01 and Well 02 are part of the phase 1-6 project that involved the development of six wells with the potential to deliver an additional 70% production increase to the LNG export market. The sand face for both wells was drilled with 0.72psi/ft pseudo oil-based mud (POBM). After the initial well clean-up, both wells produced sub-optimally (~20% of estimated potential) with relatively high drawdown (ranging from 500psi – 1000psi). This low production was suspected to be because of downhole (screen and formation) impairment or partial opening of the formation isolation valves (FIV).
A restoration team was set up with a responsibility to proffer a robust well intervention execution plan and select the most potent barite dissolver. Nine stimulation chemicals were tested and based on the team criteria, CHEM-001 and CHEM-002 were selected as main-treatment and pre-flush chemicals, respectively.
The downhole and surface conditions that exist in deep high-pressure wells pose many challenges to the coiled tubing industry as it strives to provide safe and reliable access to the wells. This paper highlights a case history of successfully snubbing coiled tubing (CT) into two deep (about 14,000ft+) live wells (Well 01 and Well 02) with a high surface pressure (7000psi+) and temperature (80 – 100°C) to stimulate both wells. The success criteria post stimulation was targeted at 75% of the potential production value. However, post treatment results show that cumulative gas production increased by 375% (with about 200psi) with a potential to increase up to 400%.
This paper details the entire operations during the CT well intervention, the planning, design, and technical analysis which led to the selection of a CT with 130,000psi yield strength on a 125K CT injector system, force simulations, and laboratory tests on CT with stimulation chemicals which led to a successful stimulation campaign. The paper also covers the initial planned versus actual operations and the lessons learned leading to on-the-spot optimization plans that resulted in a highly successful intervention operation.
Chaisoontornyotin, Wattana (University of Wyoming) | Mohamed, Abdelhalim (University of Wyoming) | Bai, Shixun (University of Wyoming) | Afari, Samuel Asante (University of Wyoming) | Mirchi, Vahideh (University of Wyoming) | Recio, Antonio (Halliburton) | Pearl, Megan (Halliburton) | Piri, Mohammad (University of Wyoming)
This work investigates the impact of fracture surface area to rock volume ratio (Af/Vr) on spontaneous imbibition at ambient conditions using ultra-tight reservoir carbonate rocks. A significantly improved insight is presented into the physics of surfactant-based enhanced oil recovery from tight and fractured formation rocks. The performance of a blank brine (2.0 wt.% KCl) and an engineered surfactant solution are compared. This work uses custom-built high-accuracy Amott cells (0.01cc resolution) to precisely measure the produced oil from the tight rock samples. Interfacial tension/contact angle (IFT/CA) measurement systems and a focused ion beam-scanning electron microscope (FIB-SEM) are used to measure interfacial tension (IFT) between the fluid phases and characterize rock samples, respectively. The measurements are then used to explain the observed recovery trends. The results reveal that volume of oil produced to volume of oil in place ratio (recovery factor, Rf) increases with increasing Af/Vr ratio before reaching a plateau. This suggests that there is a threshold Af/Vr value beyond which an increase in Af/Vr will not result in any incremental recovery for a given rock/brine/oil system. It is observed that the threshold Af/Vr value varies with the brine composition. The ultimate oil recovery is higher for all tested Af/Vr values when the surfactant is deployed. The results discussed herein can enhance the design of fracturing, the fluids, and additive packages used in hydraulic fracturing operations in unconventional oil reservoirs and is expected to help reduce associated cleanup times and costs.
Tight reservoirs are an important group of hydrocarbon-bearing geologic systems that are known to contain a significant amount of oil and gas. Production of hydrocarbons from these reservoirs, however, remains a challenge due to their low porosity and permeability. Therefore, economic development of tight reservoirs depends on the presence of fractures that can improve hydraulic conductivity of the medium. To effectively enhance the production in fractured reservoirs, the fracturing operations must be carefully optimized. The created surface area of hydraulic fractures is one of the most important parameters that significantly impacts well productivity.
The Niobrara interval in the Denver-Julesberg (DJ) Basin contains several important unconventional hydrocarbon targets. However, the Niobrara is extensively faulted, which poses challenges for accurately landing and steering laterals in zone. Insight into small faulted structures in the Niobrara using traditional manual fault interpretation techniques is challenging because of the tuning thickness in seismic data. Fault throws less than the tuning thickness are difficult to interpret and incorporate into geosteering plans. Consequently, drillers frequently find themselves out of zone after crossing these small faults. Using independent information about fault locations and throws provided from multiple horizontal wells in the DJ Basin, this paper demonstrates the fault likelihood attribute (Hale, 2013) can resolve fault throws as small as 10 ft, allowing seismic-based well plans and unconventional project economics to be significantly improved.
Traditional geoscience data interpretation workflows in support of well planning can be tedious and time consuming, requiring manual fault picking on seismic profiles in conjunction with horizon tracing and gridding for structural mapping. The emergence of unconventional resource plays requires both more efficient geoscience workflows to support round-the-clock drilling operations and more detailed structural interpretations to help ensure laterals are steered along sweet spots. Pre-drill mapping of small-scale faults is therefore of particular importance for safe operations and helping ensure that lateral wells stay in zone.
Recent advances in fault-sensitive post-stack seismic attributes are changing the way subsurface professionals think about faults and how to map them in 3D space. In particular, the fault likelihood attribute (Hale, 2013) has provided a breakthrough improvement in the quality of seismic-derived fault attributes. Typically, the fault likelihood attribute is used in exploration settings to rapidly generate a broad-scale structural interpretation, being used both as a guide to manual fault interpretation and as input into automated fault extraction algorithms. This paper demonstrates the value of fault likelihood in development settings for assisting the well planning and geosteering process.
Hydrocarbon production can be hindered as a result of fluid-induced formation damage caused by shale damage (swelling, sloughing, or fines migrating) or chemical damage (insoluble residue or polymer buildup). The proper selection of completion and stimulation fluid with additives provides the leading approach to mitigate formation damage.
Formation-specific damage mechanisms were determined from formation core, drilled cuttings, and outcrop materials for more than 100 North American resource shale samples. The formation materials were characterized using x-ray diffraction (XRD), cation exchange capacity (CEC), swelling sensitivity time (SST), mechanical stability turbidity (MST), and column flow testing to determine mineralogy, fluid sensitivity, and dominate fluid-induced damage mechanism. Preventing formation damage is predominately achieved with cationic clay stabilization chemicals. The efficacy of numerous chemical additives prepared at the same activity but with varied molecular weights (MWs) from 0.1 to 1,200 kDa was evaluated on ultra-low permeability shale samples based on reducing the swelling, fines generation, and mechanical destabilization tendencies. The same treatment chemicals were evaluated for permanency, compatibility with anionic friction reducer (FR) polymers, and mobility within porous media to determine the ideal North American formation stabilization material.
Fines generation was determined to be the dominant fluid-induced damage mechanism for ultra-low permeability North American hydrocarbon-producing formations. Clay content for these active formations range from 1 to 70 wt%, with an average of 30 wt% and a CEC of 4.5 milli-equivalence (meq)/100 g, indicating that most North American formations have moderate fluid instability. Fluid sensitives found an average swelling damage comparable to a 1 wt% smectite sample (30 seconds) mass loss due to mild mechanical agitation similar to an illite sample (3.2 wt%/hr) and fines generation due to flow approximately half of an illite sample (6.22 mg/PV). Prevention of these fluid-induced formation damage effects was determined for cationic clay stabilization chemicals ranging in MWs from monovalent salt solutions to large polymeric materials. Highly mobile monovalent salts effectively prevent swelling and remain compatible in an anionic FR solution; however, these treatments are temporary and less effective for remediating fines generation. Increasing the MW of cationic treatments improves the performance in terms of preventing swelling, fines, and wash-off; however, if the MW increase is too large, the polymers reduce permeability and become incompatible with anionic FR polymers. There is a range of moderate MW materials that provides permanent protection against swelling and fines damage while remaining compatible with anionic FRs. This range of moderate MW cationic treatments is the optimal chemical additive for most North American formations, offering the most effective protection against prevalent fluid-induced formation damage mechanisms while preventing chemical damage.
Wilcox, David (Halliburton) | Cappiello, Stefano (Halliburton) | Sevilla, Mauricio (ConocoPhillips) | Shafer, Eric (ConocoPhillips) | Gill, Greg (ConocoPhillips) | Kress, Ian (ConocoPhillips) | Sanchez, Nestor (ConocoPhillips)
Multilateral technology (MLT) is used to construct multiple horizontal wellbores that branch out from a single main wellbore. Traditionally, MLT has been used in offshore conventional environments where reservoir contact drives production and wellhead real estate is at a premium. This paper reviews a field trial of MLT in an onshore unconventional reservoir where hydraulic fracture stimulation of each lateral is necessary to produce the well.
This paper reviews the MLT used to create a new dual-lateral, fully cemented junction (TAML Level 4) well in a major North American unconventional reservoir. Drilling, Completions and Stimulation of the laterals will be addresses, including the challenges encountered and efficiencies gained.
It is possible to drill, stimulate, and produce a multi-lateral well that requires hydraulic fracture stimulation. Three main goals were successfully met with the pilot MLT well: drilled two laterals to targeted depth, independently stimulated and flow tested each lateral separately, and finally flowed both laterals commingled to determine the full potential of the MLT well. The TAML Level 4 (fully cemented) junction was mechanically and hydraulically isolated during the stimulation of both laterals. This is the first TAML Level 4 dual lateral well in an unconventional reservoir commingled at peak production.
Through this case history, key technologies and strategies that should be implemented for MLT to become widely adopted and commercially viable in the unconventional market are identified.
Facies interpretations’ fundamental inputs into three-dimensional (3D) petroleum systems models (PSM) form the basis for modeling calculations and are integral to understanding both conventional and unconventional reservoirs. Building facies models is time consuming and involves a lengthy petrophysical evaluation, and difficulties arise when data are inconsistent temporally and spatially. Machine-learning algorithms (ML), 3D basin facies models, PSM, and geostatistics have been used to constrain important properties at the local reservoir scale to produce reliable models. The final model forms show how unconventional reservoir characterization can be performed more effectively in the presence of sparse data. Here, vital reservoir properties (i.e., brittleness, maturity, porosity, pressure, and organic enrichment), often unavailable from local data, can be calculated.
Natural gas production for 2017 in the US was the second highest level ever recorded (EIA 2018). The increases since 2005 have principally been the result of horizontal drilling and hydraulic fracturing; therefore, the US currently produces approximately all the natural gas it demands and is now a natural gas exporter. The road to this remarkable success has been a fact-finding mission and lengthy process in an attempt to precisely understand what constitutes an economically viable resource. Although results are mixed, much has been learned during the process.
Currently, the US has an evident understanding of shale reservoirs and many years of data acquisition to perform in-depth analysis to identify more accurate “sweet spots” for well placement. By comparison, other countries are just beginning shale exploration and development and, as a consequence, have to leverage learnings from the North American experience. Nevertheless, some regions in Europe have strict regulations, and the opportunity for large-scale exploratory drilling is limited (Godec and Spisto 2016).
The challenge for these countries is generating insight into the reservoir without the luxury of drilling vast numbers of exploratory wells.
Shale reservoirs are complex, and finding the optimal drill site and landing zone with appropriate socio-economic factors and shale rock quality is fundamental to securing economic success. However, requirements necessary to understand the physics of the reservoir are often lacking. Although geophysical and geomechanical logs [e.g., minimum horizontal stress, Poisson's ratio, Young's modulus, total organic carbon (TOC), etc.] (Eshkalak et al. 2014) are sometimes gathered and analyzed along with seismic data, it is far too common to identify a paucity of these important data. Further, spatial distribution of wells can be irregular or sparse, and quantity can be insufficient to provide comprehensive insight into formation and reservoir properties (Casey et al. 2018), presenting a significant challenge when building reliable reservoir models.
The rapid development of a surfactant blend using statistical software tools to drastically reduce the number of laboratory experiments associated with more traditional Edisonian-type approaches is discussed. The study evaluates performance of various surfactant blends for fracturing applications in most major North American shale formation materials and crude oils.
The study entailed identifying key surfactant characteristics, such as hydrophilic-lipophilic balance (HLB), relative solubility number (RSN), and solvency. The parameters were used to create a design of experiments (DoE) with statistical software. Formulating experiments were performed as recommended by the DoE, and selected blends were subjected to tensiometer and petroleum industry application testing. Critical micelle concentration (CMC) and interfacial tension (IFT) values were captured to better understand blend physical properties. Additionally, sand pack column flow (SCF) and emulsion break time (EBT) experiments were conducted to assess blend efficacy when exposed to Niobrara, Bakken, Permian, Mid-Conn, Eagle Ford, and Gulf of Mexico (GOM) reservoir materials and crude oils. Spontaneous imbibition experiments were performed on outcrop cores.
Using a custom DoE optimized for interactions and mixtures, the formulation design space was covered with 162 formulations compared to 576 necessary for a full factorial evaluation. Analysis of the surfactant formulation with the regional specific materials revealed primary components for treatment optimization within each area. With respect to SCF experiments, incorporating proppant, fracturing fluid, and regional specific formation cuttings-to-crude oil combinations revealed that the nature of the crude oil dominated the effects of the surfactant formulations. Data analysis revealed blends that lowered the hydrocarbon/water IFT below 2 mN/M outperformed formulations that resulted in higher IFTs. With respect to EBT, progressing from Bakken to Eagle Ford crude oils, API gravities varied significantly, and these changes in chemical properties greatly impacted the testing results. Formulations with higher concentrations of demulsifier-type components performed better as crude oil API gravities decrease because of increased amounts of asphaltenes, resins, paraffins, and naphthenic acid content. When using the DoE results for ranking of surfactants, experiments in porous media revealed all surfactants formulated through the DoE outperformed the standard offerings by greater than 30% when evaluating the efficacy of the blends to displace oil from cores. However, the addition of some demulsifier-type components to the blends adversely impacted the magnitude of improved hydrocarbon recovery, which was attributed to premature adsorption onto the rock surface.
In an industry where the effect of stimulation chemicals on complex downhole environments remains uncertain, processes to identify the most import factors that impact the performance of chemical additives are of utmost importance. This exercise used statistical software to evaluate multiple complex variables associated with surfactant formulation and suggested blends that improve hydrocarbon recovery.
Elastic properties of unconventional rock, including gas/oil shale and tight gas sand (TGS), are crucial in hydraulic fracture modeling. The two most important rock elastic properties are Young's modulus and Poisson's ratio. These properties can be determined from sonic well logs, but the required logs (compressional and shear velocity) are not always available. These properties can be measured from plug samples using a triaxial load frame, but these tests are slow, expensive, and require an intact cylindrical sample.
An alternative is to use rock physics modeling applied to mineralogy and porosity computed from ion-milled scanning electron microscope (SEM) images to compute elastic constants from small rock fragments. This method can also be applied to data from whole core computed tomography (CT) scans. This approach was used to develop a digital rock workflow to compute elastic properties from rotary sidewalls cores, drill cuttings, and core CT data.
The new approach combines quantitative information obtained from 2D ion-milled SEM images with rock physics effective-medium models, the latter used to relate volume properties to elastic properties. These models can be obtained from wireline and/or laboratory measurements of bulk rock volumetrics together with elastic rock properties. This process of finding a rock physics model is called rock physics diagnostics.
The SEM images provide porosity, organic matter volume, and pore structure. The mineralogy of the sample obtained through quantitative X-ray diffraction (XRD) is added to those inputs. Well log data relevant to the local area are then used to establish a rock physics model linking the elastic properties to porosity, organic matter content, and mineralogy. These models are established for each basin and formation, based on available wireline log data. High quality wireline data is key to successful rock physics diagnostics (RPD).
In this study, wireline logs and core samples were obtained from a well in Culberson Co, TX. The zone of interest in this case was the Wolfcamp A formation. After establishing the appropriate rock physics effective medium models, the elastic properties were computed, including Young's modulus, Poisson's ratio, compressional wave velocity, and shear wave velocity from SEM images and XRD mineral data. The computed, upscaled elastic properties closely matched the log variability.
This method can be used to obtain the required elastic properties from wells that lack compressional and dipole shear wave data. This mechanical properties data can be used to compute horizontal stress, unconfined compressive strength, and other critical properties that control hydraulic fracture growth. In many cases, drill cuttings can be used for the SEM analysis. This new approach does not require cores, and so can be especially valuable in quantifying elastic and mechanical properties along the lateral wellbore where wireline logs are seldom available.
To improve economics in stacked unconventional formations, operators need measurements of downhole fluid properties and mechanical stress. The fluid properties are usually acquired at the surface by collecting samples (oil and gas) at the primary separator. However, collecting a representative sample is a challenge in multi-frac wells landed on several reservoir zones. Rock and geomechanical properties are usually inferred from uncalibrated log data, core experimental work, or a single diagnostic fracture injection test (DFIT). Without this information, operators can make suboptimal decisions. This paper discusses a case study wherein a microfracture was created at a preselected point in the wellbore, which enabled downhole fluid sampling in an unconventional formation.
Combining reservoir, stimulation, and petrophysical expertise enabled the deployment of a new microfracturing and fluid sampling service from a wireline-conveyed tool. The industry-first combined downhole microfracture and pressurized fluid sampling in an unconventional reservoir was performed. This process enabled the acquisition of quality DFIT, depth-specific mechanical properties, and in-situ formation fluid samples.
Using conventional logging tools a predefined target was identified, the wireline conveyed formation tester was used to isolate a 3’ interval to create a microfracture. Accurate pumping fluid volumes and pressures were measured when performing the microfrature, then flowback was monitored to identify invaded from formation fluids minimizing the risk of collecting a contaminated sample.
Results confirmed that this new service can break down unconventional formations and drawdown on the formation to acquire in-situ fluid samples. Valuable completion information, including fracture initiation and extension pressure, fluid leakoff character, and estimates of kh/μ were also obtained.
Fluid samples from these ultra-tight formations were previously unobtainable from a formation tester. Using the tool to generate a microfracture makes it possible to collect in-situ fluid samples in a cost-effective timeframe. This capability leads to better drilling programs, surface facility design, reserve estimation, and stimulation decisions.
This technology represents a new integration of formation evaluation and engineering. It requires planning between drilling, stimulation, reservoir engineering, and formation evaluation staff. The tool provides fluid composition and micro-DFITs at multiple depths selected by engineers and geoscientists. Information at specific depths provides new opportunities for reservoir and stimulation modeling, petrophysical calibration, and reservoir mechanics. Because this information was previously largely unobtainable downhole, new opportunities are now available to better understand the interplay between geomechanics and fluid properties.
The definition of unconventional reservoirs continues to evolve over time as advances in technology make it more viable to extract hydrocarbons. The need for reservoir characterization in such reservoirs, however, will continue to increase to optimize wellbore placement and enhance production. For high-angle or horizontal wellbores common in unconventional drilling, obtaining information from wireline technologies may be either too expensive or risky, although obtaining a wellbore stability assessment while drilling provides a key input into the real-time geomechanical model. This paper presents field test results of a new 4¾-in. ultrasonic imaging logging-while-drilling (LWD) tool that provides a real-time assessment of borehole shape and high-resolution caliper and acoustic impedance images in both water-based mud (WBM) and oil-based mud (OBM) applications.
Images from measurements, such as gamma ray, resistivity, or density, are common in LWD applications. However, high-resolution images have historically been limited to WBM applications. This paper describes the sensor physics and tool configuration that enable the acquisition of borehole caliper and acoustic impedance images in all mud types, with examples of logs obtained while drilling in boreholes using OBM. Details of the comparison with wireline data sets are also given.
Vertical and horizontal wellbores covering different lithologies are described, showing that high-resolution images are now available in slimhole OBM applications. Caliper images illustrate small changes in borehole shape, and impedance images can be used to evaluate geological features and determine stratigraphic dip. The evaluation of caliper data with a wireline multifinger caliper illustrates the potential to eliminate a separate wireline run before completing the well. Comparison of while-drilling data with tripping out of hole data provides crucial insight into wellbore deterioration with time.
The technology described addresses key challenges encountered while drilling and evaluating unconventional reservoirs. Real-time wellbore stability assessment enables optimization of drilling parameters and mud weight in all unconventional reservoirs. Identification of faults and fractures provides valuable information to optimize the hydraulic fracturing program in shale gas applications. Inputs into the geomechanical model are valuable in the assessment of tight sand reservoirs with extremely low porosity and permeability. Limestone reservoirs with minor shale content may require OBM to minimize wellbore deterioration with time. Monitoring such deterioration is critical in optimizing the placement of packers and the hydraulic fracturing program design.
Providing the industry's highest-resolution images in all mud types, even under high logging speeds represents a unique method of assessing real-time wellbore stability and enhancing formation evaluation in slim wellbores in unconventional reservoirs.