Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment.
Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.
A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates.
This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.
The use of the Diagnostic Fracture Injection Test (DFIT) technique as a means of pre-frac investigation has become relatively routine in the oilfield, particularly to understand the reservoir properties and then subsequently optimize the hydraulic fracture design. A key component of an effective DFIT is the performance of an effective After Closure Analysis (ACA) to assess the transmissibility of the formation and thereby allow for effective design.
BP Oman is developing the Barik formation, within the Khazzan field, which is a low-permeability conventional tight-gas reservoir within Block 61 of the Sultanate of Oman. The reservoir is comprised of a series of tightly interbedded sandstones and shales, with substantial shale breaks between the principal sand lobes. During the Appraisal and Development well sequence to date, BP Oman have performed DFIT operations in over 50 vertical wells, within the Barik Formation. Each one of these wells was then subject to placement of a large (one million lb) hydraulic fracture treatment. Each treatment was then followed by a standard clean-up programme and when possible a PBU, with subsequent placement on production into the main gathering system.
This paper seeks to demonstrate that there is unambiguous evidence of a coherent correlation between the petro-physical Barik open-hole logs, the transmissibility value (as estimated from the ACA), the conventional Pressure Transient Analysis (PTA) as well as the long-term production behaviour. Additionally, the paper will investigate the key aspects of the actual DFIT execution, the data gathering and the analysis that can impact the quality of the correlation. The paper will go on to demonstrate the most efficient methods of achieving the most accurate assessment of the formation transmissibility; that is both indicative and subsequently helpful for the fracture design and post-fracture productivity prediction.
This paper successfully describes a 50 well, and growing, DFIT analysis programme and the suitability of the use of the results from the subsequently performed ACAs for forward planning and hydraulic fracture design. Providing a suite of useful and helpful insights, suggestions and recommendations; into how DFIT, for ACA, should be executed in the field; the paper adds an extensive case history to the industry database for future consideration.
We recently completed a full-scale, 3-D field trial of our low-frequency seismic source technology (Wolfspar) in the Gulf of Mexico (GoM). With this survey, we acquired an industry first low-frequency, ultra-wide-offset marine seismic dataset from a widely spaced set of source lines into an array of ocean-bottom nodes (OBN). We achieved our primary goal of safe operations – no accidents, no harm to people, no damage to environment – and our geophysical goal of acquiring a high-quality, low-frequency, 3-D dataset with adequate coverage for velocity-model building via full-waveform inversion (FWI). In this paper, we share the logistics around the planning of field trial, challenges encountered prior to and during the execution of the survey, and a look into future plans for the low-frequency source technology.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 210C (Anaheim Convention Center)
Presentation Type: Oral
We conduct this study through the following 3 key steps.
Muqtadir, Arqam (King Fahd University of Petroleum & Minerals) | Elkatatny, S. M. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. A. (King Fahd University of Petroleum & Minerals) | Abdulraheem, A. (King Fahd University of Petroleum & Minerals) | Gomaa, A. (BP America)
ABSTRACT: The presence of pore fluid tends to affect the rock's physical and mechanical properties. It potentially causes drilling problems, casing failures and improper fracture propagation. It is vital to understand how much the strength of the rock is affected when saturated with fluids. Low porosity, permeability and complexities in pore structures can further thwart the effect. The effect of saturating fluid on the dynamic and static properties of low permeability Scioto sandstone outcrop samples was studied in this paper. It was seen that the Unconfined Compressive Strength (UCS) was decreased by 9% for oil saturated rocks and 25% for brine saturated rocks whereas the reduction in the tensile strength was 20% and 42% respectively. The UCS samples were monitored with acoustic emission (AE) and exhibited a series of events.
Geomechanical parameters of rocks are influenced when exposed to fluids. As the water saturation increases, a reduction in the Unconfined Compressive Strength (UCS) (Y agiz and Rostami, 2012) and Young's modulus is seen, while Poisson's ratios tends to increase (Widarsono et al., 2001). Usually sedimentary rocks are more affected by the water saturation than the igneous and metamorphic rock (Wong et al., 2016).
For carbonates, DeVilbiss (1984) partially saturated limestone rock with water and saw an attenuation in the acoustic velocities. Brignoli et al., (1995) performed UCS on fully saturated limestones and saw a 15 to 20% reduction in the Young's modulus. Fabricius & Eberli (2009) also saw a similar decrease.
Zhang et al., (2017) studied the effect of different water saturations on the geomechanical properties of siltstones. The highest reduction in strength was observed at 10% saturation. It was seen that as the water saturation decreased, the volumetric strain of the cracks and the sample decreased as a result from water easing crack initiation and propagation.
Mc Carter (2010) and Perera et al., (2011) performed UCS on coal and sandstones and saw a decrease in UCS and Young's modulus as water saturation increased. Labuz & Berger (1991) saw a decrease of 15 % in the Young's modulus as water saturation increased in granite while Vasarhelyi (2003) saw the same effect in Hungarian volcanic rocks. Henao et al., (2017) reported a significant decrease in strength in sandstone rocks when saturated with brine while a moderate decrease when saturated with dodecane.
This paper discusses how the application of a Retrievable Inflatable Bridge Plug (RIBP) helped overcome the challenges encountered in a subsea deepwater intervention operation. The technical details of the challenges are first outlined, followed by the salient features of the RIBP that facilitated its successful use. The RIBP was used to isolate the reservoir prior to change-out of the upper completion tubing as per the intervention scope of work. The monobore completion for which the intervention was planned did not have any nipple profiles to allow for reservoir isolation using a traditional lock and plug. Therefore, through-tubing Mechanical Bridge Plug (MBP) technologies had to be considered. Only the RIBP was able to provide the functionality for the intervention operation. This RIBP technology was applied successfully to two different wells with identical scopes of work. The inflatable technology provided a robust solution to the compound challenges faced during the planned intervention operation. Since these challenges are common to the industry, especially in the deepwater subsea environment, the successful RIBP application discussed in this paper increases confidence in the future use of such technology.
The Gulf of Mexico (GoM) Paleogene is an emerging oil and gas industry trend characterized by subsalt reservoirs deposited as submarine turbidites, where significant depths to drilling targets have led to high-pressure regimes. Rock properties modeling suggests that sands and shales, as well as sand quality variations, are distinguishable using seismic amplitudes across the trend, however, surface seismic technology is limited in its ability for interpreters to predict reservoir quality and stratigraphic associations due to poor angular illumination in subsalt environments. A detailed rock property model was utilized to generate synthetic 3D elastic vertical seismic profile (VSP) data at 3 well locations at a Paleogene oil field. Vertical component data (treated as PP) and horizontal component data (treated as PS) were used to produce corresponding migrated images, both using the exact velocity model. Migrated 3D VSP PP and PS images allowed robust interpretations of the model data which was tested to determine the efficacy of delineating reservoir quality, stratigraphic, and fluid variations built into the model. Results show that 3D VSPs are capable of providing meaningful subsalt amplitude images that reflect reservoir properties, data that can have a significant impact on well placement and oil recovery. Additionally, despite the excellent synthetic data quality derived from this modeling study, there are limited industry borehole seismic tools available to perform a realistic field acquisition as depicted in this model due to the depth and pressure regimes unique to the Paleogene, supporting the need for the future development of expanded arrays rated for high-pressure environments.
Presentation Date: Tuesday, September 26, 2017
Start Time: 2:40 PM
Presentation Type: ORAL
Conventional methods for velocity model building are often limited in their ability to resolve geologic features characterized by high-contrast, short-wavelength velocity variations. If left unresolved, these features lead to velocity errors that significantly degrade images of deeper targets. We propose a new approach to correct for such velocity errors. By redatuming recorded wavefields to the vicinity of the geologic features we seek to resolve, we could identify far-field wavefront phase distortions resulting from short-wavelength velocity errors. We corrected for these phase distortions by estimating static time shifts that aligned redatumed wavefields to reference wavefields computed by demigrating a guide image. Using the estimated time shifts, we could improve the image either by adjusting the redatumed wavefields or by updating the velocity model.
Presentation Date: Wednesday, September 27, 2017
Start Time: 9:45 AM
Location: Exhibit Hall C, E-P Station 3
Presentation Type: EPOSTER
Norbisrath, Jan Henrik (Statoil) | Grammer, G. Michael (Oklahoma State University) | Vanden Berg, Beth (BP America) | Tenaglia, Max (University of Miami) | Eberli, Gregor P (University of Miami) | Weger, Ralf J (University of Miami)
Nanopore geometry and mineralogy are key parameters for effective hydrocarbon exploration and production in unconventional reservoirs. This study describes an approach to evaluate relationships between low-frequency complex resistivity spectra (CRS), nanopore geometry, and mineralogy to use CRS to provide estimates of reservoir parameters concerning hydrocarbon saturation, storage, and producibility. For this purpose, the frequency dispersion of CRS was analyzed in 56 mudrock core plugs from the Vaca Muerta Formation (VMF) (Jurassic/Cretaceous) in Argentina, along with cementation factors (m), carbonate content (CO3), and total organic carbon (TOC). To quantify the nanoporosity, a subset of 23 samples was milled with broad ion beam (BIB) and imaged with scanning electron microscopy (SEM); the image grids of these samples were stitched together into high-resolution BIB-SEM mosaics and analyzed with digital image analysis (DIA) techniques. Results show that porosity is the dominant control on electrical properties in the mudrocks analyzed as part of this study. There is no conclusive evidence that pore geometry influences the electrical properties in the analyzed mudrocks. Pore-geometry parameters [dominant pore size (DOMsize) and perimeter over area (PoA)] do not correlate with electrical properties. Instead, mineralogy shows a first-order correlation with electrical properties, where cementation exponents are higher in rocks with high TOC and low CO3 content. CRS can be used to estimate porosity and cementation factors with high correlation coefficients of R2=0.71 and R2=0.95, respectively. Estimates of the 2D interfacial surface area (ISA2D), which is a function of both pore geometry and porosity, achieve an R2=0.59. The results of this study suggest that low-frequency dielectric rock properties, if measured downhole, could be useful to identify primary producing intervals in unconventional reservoirs, and to accurately determine cementation factors independent of formation fluids and porosity.
The Desmoinesian Marmaton Group, along the southern portion of the Anadarko Basin in the Granite Wash, comprises over 2,000 feet of stacked tight-sandstones and conglomerates, which host unconventional reservoirs. Uncertainty around facies variability and lateral continuity of these reservoirs represents challenges to accurate reservoir characterization due to laterally restricted submarine fan systems, and mountain-front faulting. This study examines correlations of nine ice-house flooding surfaces in 206 wells to frame fine-scale sequences in the attempt to track facies changes and estimate fault timing and duration. This high-resolution stratigraphic framework comprises a hierarchy of cycles: one 3rd-order, three 4th-order, and eight 5th-order cycles; these were mapped across fault blocks. Mapping at the 5th-order scale documented previously un-published faults and estimated duration of fault movement. Fault movement likely occurred during two separate 5th-order cycles within the stratigraphic framework. Well log trends, calibrated to core descriptions, enabled prediction of depositional environments in uncored wells across the 810-square mile study area.
The Granite Wash is a prominent 10,000-foot-thick hydrocarbon-bearing interval in the southern Anadarko Basin (Texas Panhandle and Southern Oklahoma) and it consists of tens of stacked unconventional reservoirs (Figure 1). Several challenges plague efficient exploitation of these reservoirs including: lateral discontinuities, both depositional and fault related, as well as arkosic sandstone and conglomeratic lithologies that elevate gamma ray responses and complicate petrophysical log models. In other words, when did faulting occur and how did it impact facies distribution and sequence thickness?
Assuming faulting was active during deposition of the Marmaton Group, a high-resolution stratigraphic framework constructed across documented fault blocks will highlight fault timing and duration. To better delineate these prolific reservoirs, this study will: (1) interrogate fault timing and duration; (2) calibrate well logs to core descriptions; and (3) construct integrated reservoir-scale depositional element maps.