Pendrigh, Nicole (Zonge International, Inc.) | Sirles, Phil (Zonge International, Inc.) | Carlson, Norman (Zonge International, Inc.) | LaBrecque, Douglas (Multi-Phase Technologies) | Ivancie, Paul (AMEC)
At the Captain Jack Superfund site located four miles southwest of Ward, Colorado, acid mine drainage is trickling in to Left Hand Creek, which flows in to Boulder, Co (Figure 1). The water needs to be treated and monitored. The proposed solution is to use the mine tunnels for in-situ water treatment. Therefore, there is a need to determine the location of the mine tunnel system, if possible.
There is limited information regarding the extent of mineworkings and bedrock fractures through the reservoir zone of the Big Five tunnel. While these areas are accessible for tracked drilling rigs, some tunnel segments lie 400 to 500 feet underground. Because the historical maps of mine/tunnel workings have no survey data, locating the tunnel "target zones" either involves drilling holes on 5 to 10-footspacings across multiple transects, or utilizing geophysical methods to detect/locate the tunnel voids prior to drilling. Surface applications of geophysics such as electrical resistivity (ER) are recommended to obtain subsurface “imaging” of the tunnel locations. The benefit of ER methods is that they minimize the number of drill locations and per-foot drilling expense, as well as resulting surface disturbance requiring reclamation.
Surface and crosshole geophysical investigations, including time-domain dipole-dipole resistivity and frequency domain Mise-a-la-Masse (MALM) surveys, were conducted on the Captain Jack Project
Since the geophysical surveys were completed in 2012, the site has undergone downhole Electical Resistivity Tomography (ERT) and Magnetics monitoring and modelling. The bulkhead and remediation pumping system is in place as of summer, 2017. Surface and borehole monitoring equipment is in place, and in the near-future, the valve will be closed and in-place monitoring will begin.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 204A (Anaheim Convention Center)
Presentation Type: Oral
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Seismic velocity in salt domes in the Gulf of Mexico varies due to sediment inclusions and sutures. Typically, seismic velocity of salt is slower than clean salt velocity: the maximum slowdown can be more than 20%. Therefore, it is extremely important to build a velocity model with variable salt velocity to improve the base salt interpretation, subsalt imaging and better well ties at the subsalt level. Using different seismic attributes (envelope, root-mean-square amplitude, absolute amplitude, gradient, and others) as inputs, a neural network classifies a seismic image of a salt body into a set of classes. Different classes are mapped to different salt velocities. The scalars used in the mapping are adjusted using the sonic velocity inside of the salt as calibration and the base salt tie to the well markers on seismic images. This workflow was applied to a large reprocessing project in the central Gulf of Mexico; this method has been proven to be effective and efficient, resulting in improvement in base salt events and substantially improved subsalt imaging as well as base salt well tie, all while offering improved turnaround time.
Presentation Date: Wednesday, October 19, 2016
Start Time: 2:20:00 PM
Presentation Type: ORAL
Vertical seismic profile (VSP) surveys rely on three-component (3C) geophones to acquire high-resolution data around target reservoirs. These 3C geophones are composed of three independent receivers, mounted orthogonally. When inside the borehole, the orientation of each 3C geophone is unknown. To enhance image stacking power from different receivers, it is necessary to reorient all the 3C VSP receivers to a common coordinate system.
We introduce a VSP coordinate reorientation workflow using elastic finite-difference modeling. The only condition required is an adequate knowledge of the overburden velocity. Since VSPs today are typically acquired to supplement existing surface seismic images, adequate velocity models already exist and this method can almost always be applied effectively. We conduct synthetic tests to demonstrate the robustness of our workflow with a variety of noise levels, velocity errors, and acquisition coverages. We also show a real data example from the deep water Gulf of Mexico (GoM).
Presentation Date: Monday, October 17, 2016
Start Time: 4:10:00 PM
Location: Lobby D/C
Presentation Type: POSTER
This project focuses on building a reservoir sub-sea network model for a condensate field in the gulf of Guinea, the Duke Field. It integrates the five developed Duke reservoirs, development wells and subsea network using the Petroleum Experts' Integrated Production Model suite of software, (IPM) which is widely used in the E&P industry especially for integrated forecasting, surveillance and production system optimization that require integration of surface and subsurface models. Following the acquisition and quality control of data from other teams working on the Duke Field, a network model which integrates the five Duke reservoirs, their associated wells and subsea network up to the production separator was built. The model was initialized and used to predict full field performance under different scenarios. Finally, a water injection allocation sensitivity study was performed and the results were analyzed both technically and economically. From the technical point of view, the option to reallocate 10 kbwpd from reservoir U to reservoir P-upper North and another 10 kbwpd from Reservoir ST to reservoir Q-Lower brought about the optimum recovery. This was also supported by a simple economic analysis. It was then recommended that additional water injectors be drilled in P-Upper North and Q-Lower to unlock an additional 8.4 MMSTB of reserves resulting from higher sweep efficiencies and better pressure maintenance.
Production optimization can play a major role in increasing recovery and decreasing operation cost. In many oilfields, the geology, production operations, and their related constraints are very complex. These complexities can complicate the formulation and solution of the pertinent optimization problems and increase the computational cost of finding a solution. Although full reservoir simulation provides detailed analysis and prediction of reservoir performance, the significant uncertainty and complexity of reservoir models can make the simulation results and their interpretations questionable. Moreover, in some cases, a reservoir model may not even be available to perform full simulation for performance optimization. The cost and complexity of developing full-scale simulation models, together with the considerable computational overhead associated with production optimization (especially under geologic uncertainty), call for development of fast proxy models for production optimization. To this end, various reduced-order and surrogate models have been designed to approximate the production behavior of a reservoir at a fraction of the computation required for full simulation.
We present an efficient production optimization scheme by integrating constrained optimization with fast decline curve analysis for predicting well production performance. The proposed production optimization approach is formulated as a constrained optimization problem by defining a desired objective function and a set of existing field/facility constraints. An efficient gradient-based optimization algorithm is then adopted to solve the resulting optimization problem for a single timestep. The optimization is then coupled with the decline curve analysis to predict future production rates. The optimization process is performed recursively in time for a specified duration. The predictions with the decline curve analysis are reasonable so long as the operating conditions remain unchanged. Using field data, we demonstrate that the proposed formulation can provide fast solutions to large-scale production optimization problems. The results in this paper suggest that the developed technique can be applied to improve production performance and operation efficiency with a minimal computational cost when compared to production optimization with full-scale reservoir simulation. It also offers the flexibility to adjust the problem formulation under various field conditions and is particularly useful when a full-scale reservoir model does not exist simulate the reservoir response for production optimization.
Anderson, T. (Chevron) | Fontenot, C. (Chevron) | Davey, R. (Chevron) | Dugas, J. (Quail Tools LP) | White, B. (Quail Tools LP) | Hamilton, K.A. (C-FER Technologies) | Beauchamp, P.S. (NOV Grant Prideco) | Karlapalem, L.C. (NOV Grant Prideco) | Muradov, A. (NOV Grant Prideco) | Brock, J.N. (NOV Grant Prideco)
A two-year comprehensive effort to design, test, manufacture, and deploy a new high-pressure completion tubular for Chevron's deep-water Gulf of Mexico operations is presented. The completion application expected harsh, aggressive loading modes and high pressures to be encountered. The major challenge was to design, test and manufacture a subsea completion string that would provide efficient hydraulics during the fracturing operations while ensuring mechanical and pressure integrity.
Results from comprehensive finite element modeling designed to evaluate the application loads are presented. An extensive physical test program to evaluate the structural integrity and sealability performance was conducted. The test included a series of combined load conditions which included axial loads (maximum 1,100,000 lb. tension, 215,000 lb. compression), internal (maximum 29,920 psi), external (maximum 25,279 psi) pressures, and bending loads (3°/100 ft. curvature). Multiple-step load cycles were conducted at both room and elevated temperatures.
Compared to earlier designs, the new 5-7/8 in. tubular design has double-start thread form which provides cost savings by reducing the make-up time from stab to shoulder by approximately 11 seconds saving trip time. The design's unique dual-radius thread root offers a step-change improvement in fatigue resistance. The new design also provides significant reduction in repair cost in comparison to earlier designs. The initial deployment of the new design is planned for wells in the Chevron-operated Jack and St. Malo oilfields which are located 40 km from each other (
As deep-water drilling continues to expand, high-performance completion tubulars must evolve to meet mechanical requirements and provide cost saving, efficiency, and safety.
Ekkawong, Peerapong (PTT Exploration and Production Plc.) | Kritsadativud, Pannayod (PTT Exploration and Production Plc.) | Lerlertpakdee, Pongsathorn (PTT Exploration and Production Plc.) | Amornprabharwat, Anan (PTT Exploration and Production Plc.)
Gas fields in the Gulf of Thailand (GOT) share some similar operational complexities and experience many common challenges. Such challenges include the huge number of wells and platforms, and the large, complex, interconnected pipeline network. Additionally, each well, of course, exhibits different performance, different enhanced recovery as well as different and diverse flow assurance methods. Fluid streams also vary significantly from well to well; for instance, the differences in condensate to gas ratios (CGR), water to gas ratios (WGR), and the CO2, and H2S levels. Moreover, production performance in the GOT remains very dynamic. The decline in production could be seen early, even though proper reservoir management was achieved because most of the reservoirs were small and compartmentalized. Optimizations aiming to maximize revenue from these fields are very challenging.
State-of-the-art industry solutions to these problems are provided by integrated production modeling, and reservoir simulation. At first consideration, they appear to be reasonable tools that can physically describe the flow of fluid, whether in a reservoir, well or surface facility; however, these tools may not serve well for the complicated compartmentalized characteristics of the gas fields in the Gulf of Thailand. Currently, determining optimum natural gas production rates in the GOT is performed by manually fine-tune the production rate using information from the latest well testing data. This method may simple and convenient but requires large effort and does not guarantee the optimal solution.
This study presents a more efficient production optimization scheme integrating constrained optimization with decline curve analysis to predict future well production performance. The project net present value is translated into the objective function, comprising maximizing condensate production and minimizing waste water production while also honoring daily gas production nomination. Well performance, export specification, and the capacity of pipeline networks are formulated as system constraints. A linear programing optimization algorithm is then used to solve the resulting optimization problem for a single time step. Next, the optimization is integrated with the production decline trend from the decline curve analysis to obtain the forecast of future production performance.
Tested against the production data of a large gas field in the Gulf of Thailand, this method showed a significant increase in the condensate production and a decrease in the water production. This solution not only enhanced production, but also reduced tedious time required for modeling, history matching, or manually configuring well production. Main assumptions, limitations and the conclusion of the proposed method are also included in this study.
Similarly, no conventional proppant can provide the required conductivity at the 20, 000 psi closure stresses (and higher) anticipated in the formations such as those found in the Lower Tertiary of the deepwater Gulf of Mexico. With the development of these reservoirs, whether in the GOM or other offshore applications, there now exists a gap in downhole proppant performance and technology. This paper will document and present the results of years of research prompted by deepwater GOM operators, resulting in a new proppant that has been developed specifically to meet these challenges. The step change advancements achieved by this new proppant will be presented, including technology improvements in both raw materials and manufacturing process. It will present unique proppant properties regarding shape, sizing and strength, never before seen in conventional proppants.
Chavez E, Marco A. (Baker Hughes Inc) | Garcia, Gonzalo Alberto (Baker Hughes Inc) | Pogoson, Eguaoje James (Baker Hughes Inc) | Li, Lisa (Baker Hughes Inc.) | Cardona, Andres H. (Baker Hughes Inc) | Nelson, Roy N (Baker Hughes Inc)
In developing an encompassing well completion design, an integrated, comprehensive solution study was under taken for the Lower Tertiary, mainly Wilcox Formation in the Gulf of Mexico. The study included reservoir characterization, optimized hydraulic 3D fracture design and modeling, nodal analysis and production forecasting and reservoir simulation to determine optimum well completion requirements such as internal tubing diameter, completion tool inner strings and downhole control valve sizes.
Preliminary studies from the Wilcox Formation were taken into consideration. Assuming a 3000-ft. MD gross height for the Wilcox formation, a representative LAS file containing the main curves for this formation was stretched out to have representative curves for the gamma ray, resistivity, neutron porosity, density, sonic delta compressional and values of core permeability.
The pore pressure and stress gradients were defined for each of the zones selected for stimulation. The stress profile was calculated implementing the Gamma Ray Index (GRI) and VShale on a per-foot basis for the zones selected withthe gamma ray curve and the assumed input values for sand and shale.
The mechanical properties were calculated from correlations for Vp and Vs utilizing the Vsh values as defined above, which in turn determined the dynamic values for Young Modulus and Poisson on the same per-foot foundation. Additional calculations were performed to determine the static values of the same characteristics for each of the selected zone depths.
The optimum well completion configuration was determined by evaluating: the fracture design (optimum treatment schedule for each zone) and minimizing pressure losses in the production tubing. Well completion reservoir simulations assisting to estimate the flow velocity during the well life. The production system was designed to not exceed the critical erosion velocity of the downhole equipment.
The study supports re-defining the well completion design requirements (maximum ratings) for ultra-deep water, high pressure and temperature applications.