Araujo, Mariela (Shell International Exploration and Production Inc.) | Chen, Chaohui (Shell International Exploration and Production Inc.) | Gao, Guohua (Shell International Exploration and Production Inc.) | Jennings, Jim (Shell International Exploration and Production Inc.) | Ramirez, Benjamin (Shell International Exploration and Production Inc.) | Xu, Zhihua (ExxonMobil) | Yeh, Tzu-hao (Shell International Exploration and Production Inc.) | Alpak, Faruk Omer (Shell International Exploration and Production Inc.) | Gelderblom, Paul (Shell International Exploration and Production Inc.)
Increased access to computational resources has allowed reservoir engineers to include assisted history matching (AHM) and uncertainty quantification (UQ) techniques as standard steps of reservoir management workflows. Several advanced methods have become available and are being used in routine activities without a proper understanding of their performance and quality. This paper provides recommendations on the efficiency and quality of different methods for applications to production forecasting, supporting the reservoir-management decision-making process.
Results from five advanced methods and two traditional methods were benchmarked in the study. The advanced methods include a nested sampling method MultiNest, the integrated global search Distributed Gauss-Newton (DGN) optimizer with Randomized Maximum Likelihood (RML), the integrated local search DGN optimizer with a Gaussian Mixture Model (GMM), and two advanced Bayesian inference-based methods from commercial simulation packages. Two traditional methods were also included for some test problems: the Markov-Chain Monte Carlo method (MCMC) is known to produce accurate results although it is too expensive for most practical problems, and a DoE-proxy based method widely used and available in some form in most commercial simulation packages.
The methods were tested on three different cases of increasing complexity: a 1D simple model based on an analytical function with one uncertain parameter, a simple injector-producer well pair in the SPE01 model with eight uncertain parameters, and an unconventional reservoir model with one well and 24 uncertain parameters. A collection of benchmark metrics was considered to compare the results, but the most useful included the total number of simulation runs, sample size, objective function distributions, cumulative oil production forecast distributions, and marginal posterior parameter distributions.
MultiNest and MCMC were found to produce the most accurate results, but MCMC is too costly for practical problems. MultiNest is also costly, but it is much more efficient than MCMC and it may be affordable for some practical applications. The proxy-based method is the lowest-cost solution. However, its accuracy is unacceptably poor.
DGN-RML and DGN-GMM seem to have the best compromise between accuracy and efficiency, and the best of these two is DGN-GMM. These two methods may produce some poor-quality samples that should be rejected for the final uncertainty quantification.
The results from the benchmark study are somewhat surprising and provide awareness to the reservoir engineering community on the quality and efficiency of the advanced and most traditional methods used for AHM and UQ. Our recommendation is to use DGN-GMM instead of the traditional proxy-based methods for most practical problems, and to consider using the more expensive MultiNest when the cost of running the reservoir models is moderate and high-quality solutions are desired.
When producing hydrocarbons from an oil well, managing erosion of both surface and subsurface components caused by solids in the flow stream is critical to maintaining operations integrity in both land and offshore assets. Although component lifetime prediction has advanced in the past few decades, the prediction's accuracy remains a major oil and gas industry challenge. Current computational models only provide an initial erosion rate which is usually assumed constant until equipment failure. However, observed erosional rates vary as a function of time due to the geometrical changes caused by equipment material loss, which result in variations in solid particle impingement velocity [
This paper presents an implementation of an erosion dynamics model in ANSYS FLUENT, a commercial computational fluid dynamics (CFD) software, to capture the progression of transient erosion. The model has the capability to capture the effects of surfaces receding from erosion at each time interval. By dynamically adjusting these surfaces and recalculating the local flow conditions in the area, this method can predict new erosion rates for each time interval and achieve fully coupled geometry-flow-erosion interactions.
This new erosion dynamics model was validated against experimental data from both literature and physical testing, and was determined to have accurately captured the observed erosion trends over time in terms of location and magnitude. The model was then employed to study two real world applications: 1) in evaluating the erosion risk for a high-rate water injector, it predicted the evolution of damage to a coupler designed to connect different diameter pipes, and 2) in analyzing facility piping systems connected to an unconventional well, it predicted the transient erosion trend from proppant flowback, which allowed for pipe geometry optimization to increase in erosional life expectancy.
Carbonate reservoirs are often comprised of a heterogeneous pore system within a matrix of variably distributed minerals including anhydrite, dolomite, and calcite. When describing carbonate thin sections, it is routine to assign relative abundance levels to each of these components, which are qualitative to semi-quantitative (e.g. point-counting) and vary greatly depending on the petrographer. Over the past few decades, image analysis has gained wide use among petrographers, however, thin section characterization using this technique has been primarily limited to the pore space due to the difficulty associated with optical recognition beyond the blue-dyed epoxy associated with the pores. Here, we present a new method of computerized object-based image segmentation (Quantitative Digital Petrography: QDP) that relies on a predefined rule set to enable rapid, automated thin section quantification with only minor human interaction. We have developed a novel work flow that automatically isolates the sample on a high-resolution (i.e. <1μm/pixel) scanned thin section, segments the image, and assigns those segments to predefined categories – e.g., pores, cement, grains, etc. Using this technique, statistically relevant numbers of thin sections can be rapidly processed and quality controlled, thereby allowing quantitative data such as MICP, wettability, and surveillance data to be integrated with the petrographic observations for a more complete description of the carbonate rock. Our technique can also incorporate multiple layers, such as cross-polarization, Back Scatter Electron (BSE) imaging, and elemental maps, which allow additional information to be easily integrated with results from QDP. The QDP approach is a significant improvement over previous digital image analysis methods because it 1) does not require binarization, 2) eliminates the subjectivity in assessing abundance levels, 3) requires less hands-on time for the petrographer, and 4) provides a much fuller dataset that can be incorporated across an entire well or field to better address common challenges associated with carbonate reservoir characterization, such as understanding pore type and cement abundance, pore connectivity, grain distribution, and reservoir flow characteristics.
Ivan, Catalin (ExxonMobil) | Al Katheeri, Yousif Saleh (ADNOC Offshore) | Reichle, Melanie (ADNOC Offshore) | Akyabi, Khalid (ADNOC Offshore) | Ryan, James Thomas (ADNOC Offshore) | Seales, Sheldon Peter Anthony (ADNOC Offshore) | Kustanto, Sigit (ADNOC Offshore) | Hayden, Laurie (M-I SWACO) | Steele, Christoper (ELKEM)
This paper covers the seven year history of the reservoir drilling campaign offshore Abu Dhabi, from the early use of a solids free, brine/water-based mud to the recent application of non-damaging, non-aqueous fluids with micronized acid-soluble ilmenite. Details are provided on the integration of the filter-cake breakers with the various types of drilling fluids, from dormant drilling fluid additives to delayed, pH and temperature activated breakers. The paper will cover on the operational implementation and lessons learned from applying all these fluids, both in the drilling and completion/breaker placement phases and describes the avenues undertaken to achieve these performance goals.
Data related to well information, reservoir rock type and completion type was gathered and analysed. Fluid Interaction and other studies were performed to determine the suitable fluid type, formulation etc. Various additional things were taken into consideration such as offset well data, drilling requirements, environmental considerations, logging requirements and likely mud damaging mechanisms. Extensive lab tests were conducted, some of which included compatibility of various fluids, return permeability, changes to the oil-water ratio, internal phase composition (heavier CaBr2 instead of CaCl2) and a micronized, acid soluble ilmenite as a weighting agent. The breaker systems saw the same extent of refinement, from enzymes to delayed organic acid precursors and chelating agents to evaluate the removal of the fluid filter cake by the breaker. Fluids formulations were evaluated and optimized based on observations.
Over eighty extended reach drilling (ERD) wells have been drilled using both Reservoir Drill-in Fluid (RDF) systems: water-based mud RDF, and Non-Aqueous Fluid (NAF) RDF, each with specially formulated Breakers. These wells provided lessons learned which contributed to the current design and formulations which are in use today. Friction Factors (FF) obtained using RDF NAF proved to be much lower than those with RDF WBM. The lower friction factors enabled wells with longer horizontal sections within the reservoir to be drilled successfully and at significantly higher Rates of Penetration (ROP). The use of micronized, acid soluble ilmenite also led to achieving lower ECD as compared to sized calcium carbonate. The evolution of breaker formulations also allowed for longer breakthrough time to be obtained which allowed for better coverage of the lateral, better removal of the filter cake, and ultimately enhanced production through improved inflow profiles. The end result of the continuous improvement in reservoir drilling fluid was a first of its kind non-aqueous fluid that combined the desired properties of low rheological profile for ECD management, low coefficient of friction and being non-damaging.
Gudipati, Vikas (ExxonMobil) | Jaynes, Scott (ExxonMobil) | Lee, Sunwoong (ExxonMobil) | Reilly, Joseph (ExxonMobil) | Lazaratos, Spyros (ExxonMobil) | Neelamani, Ramesh (ExxonMobil) | Martinez, Alex (ExxonMobil) | Zulfitri, Armand (ExxonMobil) | Onn, Fayaz (ExxonMobil) | Shaw, Chris (ExxonMobil) | Ghazali, Ahmad Riza (PETRONAS Carigali) | Konuk, Tugrul (PETRONAS Carigali) | Khalil, Adbel Ashraf A. (PETRONAS Carigali) | Nghi, Nguyen Huu (Malaysia Petroleum Management)
A case study is presented wherein broadband processing, FWI, and Q migration have been used to address poor imaging due to complex-overburden and amplitude-loss. The area of study is a producing oil field in offshore Malaysia, where seismic imaging was impacted by extensive shallow gas accumulations. OBC and streamer data were used to produce high-resolution subsurface velocity models via FWI. Our results show that modern processing methods combined with FWI can provide significant imaging uplift and reduce interpretation uncertainty, even with seismic data that are decades-old.
Presentation Date: Wednesday, October 17, 2018
Start Time: 9:20:00 AM
Location: Poster Station 7
Presentation Type: Poster
Acid jetting, as a well-stimulation method for carbonate reservoirs, has shown optimistic results in the production enhancement of some extended-reach horizontal wells. It was used initially to promote damage removal along a wellbore by means of multiple strategically located injection nozzles. It has the potential to place the injecting fluid at the locations that need stimulation. Jetting may also enhance wormhole propagation compared with conventional matrix acidizing. The hypotheses for the design of more-efficient stimulation treatments are currently being investigated.
We have conducted an experimental study to investigate the effect of jetting on wormhole efficiency. Each jetting experiment was conducted as a constant-pressure (equivalent to a desired initial flux through the core) linear coreflood test, in which a standoff distance is maintained between the injection nozzle tip and the core. At low-velocity acid injection, jetting effectively removes mud filter cake by mechanical actions. Jetting also creates wormholes in limestone cores. The combination of mechanical and chemical reaction stimulates limestone rocks better than matrix acidizing without the jetting nozzle. When the jetting velocity increased, the dissolution pattern changed. An isolated local compact dissolution results in a cavity at the entries of core samples by jetting, followed by a wormhole structure. With the known dissolution pattern, sensitivity studies are carried out to investigate the effect of various parameters on the experimental outcome.
We used Indiana and Winterset limestone rocks in the experiments. A 15% hydrochloric acid (HCl) (by weight) at ambient temperature was used, and the core dimensions were 4 in. in diameter and 16 in. in length. Various combinations of acid jetting velocities and acid fluxes were considered. The Winterset limestone cores are more heterogeneous, with higher porosity and lower permeability than the Indiana limestone cores. The experimental results from the two different rock samples are compared.
Overall, the experimental results indicate that acid jetting follows the same trend as matrix acidizing, regarding wormhole propagation after cavities are created. Jetting velocity and acid flux are the critical parameters in jetting design for optimal stimulation results. Acid jetting tends to create different dissolution patterns for the cores from Indiana limestone and Winterset limestone. The observations from this work highlight the importance of understanding the dynamic physical and chemical process of jetting in the design of successful acid-stimulation jobs.
It is well known in the industry that the environment for all offshore oil and gas marine operations has unique challenges the world over. However, when operating in a subarctic region with notoriously difficult sea states, regular encounters with sea ice, icebergs, strong winds, thick fog and numerous forms of solid and liquid precipitation, the challenges become a major consideration for even the most straight forward task. It was in this very environment in Newfoundland and Labrador (NL), Canada, the Hebron Project safely and successfully executed a number of very complex, industry first, major marine operations. Successful management of these major operations was only possible due to a strong, experienced team who were able to balance critical technical planning processes with an appropriate risk based approach to decision making. The basis for this approach to planning and executing these marine activities for the Hebron Project will be explained in this paper, including some of the key success factors that enabled the team to overcome many safety, environmental and technical challenges that were encountered.
Duncan, Tim (Talos Energy LLC) | Braathen, Bjørn Inge (Statoil) | McCormack, Niall (BHP Billiton Petroleum) | Stauble, Martin (Shell) | Campbell, Lorna (ExxonMobil) | Cizek, Mark (Williams) | Rasmussen, Stein (SBM Offshore) | Khurana, Sandeep (Granherne, A KBR Company) | Wilson, Julie (Wood Mackenzie)
The Gulf of Mexico (GOM) has gone through many waves of exploration and development, each time reinventing and pushing the boundaries. Finally, the realization of crossing boundaries and combining United States and Mexico GOM into "One GOM" commercially and technically is within reach. One GOM resource base - discovered remaining to be produced and prospective - is reaching 50 billion barrels of oil equivalent (BBOE). New plays in the U.S. GOM and the opening of the Mexican GOM, coupled with innovative technological and commercial models and increasing interest from the investment community, are poised to drive value and keep this resource base and production growing further.