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Regional Service Awards recognize significant volunteer service to SPE. The Regional Public Service Award recognizes distinguished public service of SPE members at the regional level to country, state, community, or public, with respect to local custom, through excellence in leadership, service, or humanitarianism, provided the service is over and above requirements of employment. The Regional Service Award recognizes exceptional devotion of time, effort, thought, and action as to set them apart from other contributions. The Regional Young Member Outstanding Service Award is intended to encourage interests among the young members of the Society that are broader than the profession, and no award shall be presented solely on the basis of a candidate's contribution to the Society, the profession of petroleum engineering, or the petroleum industry. Recipients must be age 35 and under, exhibit leadership to the public, and the community, as well as leadership to SPE, the profession, or the petroleum industry.
Nagoo, A. S. (Nagoo & Associates) | Kulkarni, P. M. (Equinor) | Arnold, C. (Escondido Resources) | Dunham, M. (Bravo Natural Resources) | Sosa, J. (Jones Energy) | Oyewole, P. O. (Proline Energy Resources)
In this seminal work, we reveal for the first time an extensively field-tested, demonstrably accurate and simple analytical equation for the calculation of the critical gas velocity limit (or onset of liquid flow reversal) in horizontal wells as an explicit and direct function of diameter, inclination and fluid properties. For the independently verifiable and first-of-its-kind multi-play field validation study, we carefully assimilate a very large database of actual horizontal gassy oil and gas liquid loading wells from several unconventional U.S. shale plays with different bubble point and dew point fluid systems and varying gas-to-liquid ratios and varying water cuts. The shale plays in our validation database include the Eagle Ford, Woodford, Cleveland Sands, Haynesville, Cotton Valley, Fayetteville, Marcellus and Barnett formations within their associated Western Gulf, South Texas, Arkoma, Western Anadarko, East Texas, Appalachian and Permian basins. Then, after summarizing our comprehensive field testing results, practical production optimization applications of the new analytical equation and advanced use cases of interest are further highlighted in various liquid loading prediction and prevention scenarios.
As opposed to prior critical gas velocity calculation methods (droplet reversal-based, film reversal-based, flow structure stability/energy), video observations both in the lab and the field clearly show continuously-evolving, co-existing and competing flow structures even with simple fluids without mass exchanges. Therefore, this work avoids skewed assumptions on demarcating the prevailing or dominant flow structure. Instead, the new analytical equation developed is based on an analysis of the major forces in the flow field, namely the axial buoyancy vector, the convective inertial and the interfacial tension forces, in combination with an assumption of the onset of liquid flow reversal based on flow field bridging (Taylor instability). Since the new analytical equation was formulated using these minimalist assumptions, this unique characteristic results in the highest predictability obtainable for the critical gas velocity calculation because there is the least amount of uncertainties (fudge factors). The consistent accuracy of the equation against our extensive horizontal well liquids loading database verifies this fact. Moreover, the simplicity of form of the equation makes it easy to use in that every practicing engineer in practice can perform fast hand or spreadsheet calculations. In effect, this equates to having a model as simple as the Turner model but now with additional direct functions of diameter and inclination. Also, the results clearly invalidate the need for artificial variables (such as interfacial friction factor) that cannot be directly measured in any experiment. In terms of usage, the new model is used in liquid loading prevention scenarios such as end-of-tubing (EOT) landing optimization and tubing-casing selection. Evidently, this work proves that no complex, computer-only procedure is necessary for accurate critical gas velocity calculation. This finding has significant speed and improved answer-reliability implications in strong favor of the presented simple equation for use in artificial lift, production optimization and digital oilfield software in industry, in addition to being ideally suited for ‘physics-guided data analytics’ applications in real-time production operations environments.
Buenrostro, Adrian (Saudi Aramco) | Arevalo, Alfredo (Saudi Aramco) | Alzaid, Mustafa (Saudi Aramco) | Abulhamayel, Nahr (Saudi Aramco) | Driweesh, Saad (Saudi Aramco) | Chacon, Alejandro (Halliburton) | Fadul, Jose Camilo Jimenez (Halliburton) | Noguera, Jose (Halliburton)
Drilling technologies are constantly being developed as operators push the envelope limits to maximize reservoir contact and increase hydrocarbon recovery. These advancements in well construction challenge the well intervention community to seek innovative solutions to successfully intervene in these wells. This paper discusses the successful combination of a slim OD measurement-while-drilling (MWD) tool run on coiled tubing (CT) for real-time survey of the open hole lateral wellbore, followed by a stimulation treatment at appropriate depths for all laterals in a single CT run.
Saudi Arabia has been in the forefront of maximum reservoir contact well construction with the drilling of multilateral open hole gas wells; thus, the need for CT operations to enhance current offerings and procedures. For this application, several tests were performed to determine the feasibility of the combination of necessary tools to be able to steer, identify, and pump the stimulation treatment in a single run. MWD tools were run on CT in this multilateral gas well, and the stimulation treatment was performed during the same CT run.
The common practice in the study area was to run in hole down to total depth (TD) and determine, only by depth difference, in which lateral the CT was located. The uncertainty level increased exponentially when TDs of the laterals were within hundreds of feet because the treatment could potentially be performed in an alternate lateral, rather than the one intended (
The MWD tool run on coiled tubing (CT), implemented a procedure explained in this paper to eliminate the uncertainty associated with previous technologies used for in real-time CT positioning inside the wellbore. The CT position is now reliable verified by survey match with real time readings from CT tip, allowing the certification of job placement in the desired wellbore path, to complete the intervention associated to the CT intervention; i.e.,: "a stimulation treatment" to be done specifically and independently for all laterals in a single run on each. This project open the doors for many other MWD-guided CT interventions to be applied in such conditions.
Unconventional gas wells often show linear flow during their transient period, and this transient behavior can last for several years. Currently industry uses typecurve matching technique to analyze this linear flow. The typecurves in common use are based on the assumption that wells produce at constant rate. However, most of the time, the production rate is variable, and in fact is closer to constant pressure operation. The constant pressure typecurve is useful but not suitable when both rate and pressure vary. It is necessary to have an easy-to-use method for analyzing variable rate/pressure data in linear flow.
There are two objectives for this paper. First, it serves to review the formulation, typecurve, specialized plots and superposition time that are used to analyze transient linear flow. It helps readers gain a deeper understanding of the theory. Second, it serves to illustrate a practical and effective way for analyzing variable gas production data.
In this development, we studied the effect of skin on the typecurve and on the specialized plot. We converted the constant pressure solution to its constant rate equivalent by using material balance time and found it to be acceptable for all practical purposes. We converted real time to corrected pseudo-time to account for variable gas properties, and found the effect to be small in the analysis of actual production data. We investigated the effect of outliers on superposition time. In the end, we proposed an approach to analyze variable rate/pressure data during transient linear flow and confirmed the validity of our methodology using synthetic data that generated in numerical models.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140556, "Integration of Production Analysis and Rate/ Time Analysis by Use of Parametric Correlations - Theoretical Considerations and Practical Applications," by D. Ilk, SPE, Texas A&M University/DeGolyer and MacNaughton; J.A. Rushing, SPE, Apache Corporation; and T.A. Blasingame, SPE, Texas A&M University, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed.
Well-performance analysis in unconventional reservoirs is a challenging task because of the nonuniqueness associated with estimating well and formation properties. Also, estimating of reserves can be uncertain because of the very long transient-flow periods. Recent semiempirical rate/time relations have been shown to model the rate/time behavior properly for wells in unconventional reservoirs. This study focused on finding theoretical and empirical relationships of rate/time-model parameters with well and formation properties.
Unconventional-reservoir systems (e.g., tight-gas-sand, shale-gas, tight/shale-oil, and coalbed-methane reservoirs) have become a significant source of hydrocarbon production, and they offer high potential for reserves growth and future production. Complex geological and petrophysical systems describe unconventional reservoirs in addition to heterogeneities at all scales similar to conventional-reservoir systems. Because of the low-to-ultralow permeability, well-stimulation operations (e.g., single or multistage hydraulic fracturing) are required to establish production at commercial rates.
Analytical and semianalytical modeling of horizontal wells connected to multiple transverse fractures is important in terms of diagnosing well-performance behavior. At early time, the dominant flow is linear (perpendicular to the fracture face) until pressure transients of the individual fractures begin to interfere, leading to a compound-linear-flow regime. A semianalytical solution can model the entire range of flow regimes surrounding a horizontal well with multiple fractures. The solution includes a dual-permeability region near fracture faces to represent the complex fractured region surrounding the primary planar hydraulic fractures.
Reserves estimation for unconventional-reservoir systems has been performed primarily by use of conventional Arps’ decline-curve relations. Application of Arps’ relations (specifically the hyperbolic relation) for reserves estimates yields significant overestimates of reserves because Arps’ relations are applicable only during a boundary-dominated-flow regime, whereas unconventional-reservoir systems exhibit extremely long transient-flow periods. Recently, two rate/time relations were introduced to estimate reserves in unconventional reservoirs in the form of the “stretched exponential function.” These relations have proved to be successful in modeling the rate/time behavior properly, and these relations provide consistent and more-realistic reserves estimates compared with Arps’ decline relations.
Efficient removal of cuttings from the wellbore is one of the major considerations during a successful drilling operation. Fluid velocity is known to be the most dominating drilling parameter on hole cleaning. If the fluid velocity is lower than a critical value, a stationary bed develops, which leads to problems like pipe stuck, high torque-drag, increase in bottomhole pressure, increase in hydraulic horsepower requirements, etc. During a drilling operation, besides the fluid flow and presence of cuttings, there is pipe rotation. Determining the pressure losses in such a complex system is very difficult. This study aims to estimate the frictional
pressure losses in horizontal and highly inclined wells considering pipe rotation and presence of cuttings. Extensive cuttings transport experiments have been conducted on METU Cuttings Transport Flow Loop using pure water as well as numerous waterbased muds consist of different concentrations of xanthan biopolimer, starch, KCl and soda ash, weighted with barite for various inclinations, flow rates, rate of penetrations and pipe rotation speeds. Pressure drop within the test section, and stationary and/or moving bed thickness are recorded besides the other test conditions. Observations showed that, pipe rotation has a significant influence on decreasing critical velocity required to prevent stationary bed development, especially if the pipe is making an orbital motion. However, after a certain pipe rotation speed, no additional contribution of pipe rotation is observed on critical velocity.
Moreover, a reduction in the pressure drop is also observed due to the bed erosion while rotating the pipe, when compared with no pipe rotation case under the similar drilling conditions. Empirical correlations are developed based on the experimental data for estimating pressure drop. It is observed that the results obtained from the correlations are reasonably accurate, within an error range of 10% for estimating pressure drop, when compared with the experimental observations.
One of the small assets in Shell Malaysia E&P has adopted a methodology earlier implemented by Aera in California, USA, hereafter referred to as "LEAN." The concept is to increase organization efficiency by applying Toyota manufacturing principles. This is achieved through continuous improvement of processes, while minimizing waste.
Before implementation, an assessment of the pilot asset revealed fragmented efforts and inefficient collaboration between different disciplines supporting Well & Reservoir Management. In general cycle times between identification of problems and closing them out were long and below corporate standards.
The pilot project yielded almost immediate benefits. WRM cycle times were reduced by an average of 60% through co-location of key disciplines and work standardization. This enabled the existing well production to significantly exceed targeted production and a clear reduction in overall field decline has been observed. The key conclusion is that LEAN practice, originally directed towards manufacturing operations, is a highly effective way to overcome performance issues in existing assets, and can be replicated globally across diverse operating environments.
This paper will reveal new information from field operations, and demonstrates two technical contributions: detecting events from ongoing field surveillance activities such as well tests and real time meter monitoring, and dispatching a continuous flow of modeling, planning and remediation tasks to keep pace with events.
Dou, Hong'en (Research Inst. Petr. Expl/Dev) | Chen, Changchun (RIPED, PetroChina) | Chang, Yu Wen (Research Inst. Petr. Expl/Dev) | Fang, Yanjun (Daqing Oilfield E&D Research Inst.) | Chen, Xinbin (RIPED, PetroChina) | Cai, Wenxin (CNODC,CNPC)
Intercampo oil field, which contains unconsolidated reservoirs driven by edge water and bottom water, is characterized by heavy oil with mid-high permeability and high oil saturation. The three classical models of the Arps model were applied in 13 horizontal and vertical wells in the oil field; also, the paper introduces two models that are not widely applied for decline analysis and forecasting in the wells. Decline features between vertical and horizontal wells were compared. The results accord well with the actual data from the oil field. The authors point out that these decline analysis models are applicable not only for vertical wells but also for horizontal wells. The authors would like to emphasize that four decline models discussed in the paper. In regard to screening and comparison of decline analysis models, this paper illustrates how to select and use a model, as well as the model's application conditions and their features. The screened models are recommended for production performance analysis of wells, reservoirs and oil fields.
Existing decline curve analysis techniques, which include three Arps models (exponential, hyperbolic, and harmonic, 1945), and the Fetkovich model (1980), are derived empirically; the Arps models are still the preferred method for forecasting oil production and proven reserve. These methods have played a very important role in the exploration and development of oil fields worldwide (Arps 1945, Arps 1956, Fetkovich et al. 1980, Fetkovich et al. 1987, Fetkovich et al. 1996).
Gentry and McCray (1978) presented a method to define decline curve. They claimed their equation might be superior to the Arps equations by defining certain decline curves. However, the model was derived from the hyperbolic model of the Arps model; their equation has a parameter qi of initial production rate computed by the Darcy Law. This means that the application of their method requires more parameters, such as relative permeability curve, radius of drainage, formation thickness, reservoir pressure at external drainage radius, and well bore terminal pressure. On this point, in their example the extrapolation with their model is not seen because the method is not a pure production-time relationship. Furthermore, use of this model to extrapolate future production is restricted by the data requirements.
Li and Horne (2002, 2005) developed an analytical model, called the Li-Horne model, based on fluid flow mechanisms. The model was developed under the spontaneous water imbibition condition. Li and Horne also thought it difficult to predict which Arps equation a reservoir would follow. However, they made a conceptual error in their reasoning of the Arps models. In fact, we need to judge the decline type before using the Arps model to make production decline analysis. Li and Horne used only two special cases of decline exponent, n = 0 and 1, then compared the exponential model and harmonic model with any models. Hence, we think Li and Horne's comparison of several oil fields is not meaningful in cases where they did not get a concrete decline exponent n. When the Li-Horne model was applied to the actual oil fields, the values of a0 and b0 were regressed from the actual oilfield data, but not the calculation values from their equations. Because the models constants of the Arps and Li-Horne model regress from the actual oil fields, they include different reservoir type and fluid flow information (high permeability, low permeability, naturally fractured low permeability, complex, fault reservoir, etc.; single flow and multiphase flow, etc.). Therefore, the decline analysis models based on purely statistical models do not have any association with fluid flow mechanism, reservoir types, fluids characteristics, steady or unsteady flow, and single or multiphase flow. We are inclined to refer to this as an empirical rather than an analytical model.
The other two decline analysis models introduced in this paper, the Orstrand-Weng model (Arps 1945, Weng 1992) and the T model, were both proposed for predicting oil field production in China during the 1980s.
The main purpose of this paper is to compare application conditions and results among four models: Arps, Orstrand-Weng, T and the Li-Horne model.
DISCUSSION INCREASED RECOVERY OF CONVENTIONAL CRUDE OIL Chairman: WANG DEMIN, Vice President, Head of R&D Daqing Petroleum Administration Bureau, China The session, opened at 15:30 of 13 October 1997 in Hall B of China World Hotel's Conference Hall, was presided over by Chair WANG DEMIN. In his opening remarks, Mr. WANG emphasized the importance of technology in improving recovery of conventional crude oil. Presently, in the field of pro- duction, the most essential problem is still to maxi- mize the ultimate recovery in discovered reservoirs and to develop low permeability and viscous crude reservoirs. Improving oil recovery to its possible limits are the eternal theme for oil production. According to statistics up till now, the estimated proven reserves in the world of conventional crude are 145.3 billion tons, in which 58% are from sand- stone reservoir and 42% are from carbonate reservoir. The production rate is 9.5 million tons per day and 3.4 billion tons per year. Methods for increasing oil recovery have contin- uously improved from primary to secondary oil recovery methods, such as water injection and gas injection, to improved recovery methods, like water shutoff, infill drilling, horizontal wells and WAG process and so on, to enhanced oil recovery methods, including thermal, chemical, miscible and microbial recovery methods. Water injection has made us obtain a 34% recovery rate which is much higher than primary which is 10-15%; Low permeability reservoirs benefited from large-scale hydraulic frac- turing; The number of horizontal wells has been sig- nificantly increased in the oil fields all over the world and has brought distinct economic advantages and increased oil recovery; Polymer flooding will further increase oil recovery and chemical flooding tech- niques are also improving. The first speaker is Dr. ABDULAZIZ UBAID AL-KAABI (Research Institute of KFUPM, Saudi Arabia). He presented the research experience under- took at the institute of KFUPM concerning the major influence of rock mechanical parameters on the recovery of hydrocarbons from sandstone reservoirs, including fields with the potential for sand production as well as tight deep ones where hydrau- lic fracturing is often necessary to improve pro- duction rate and overall recovery. J. M. JOSHI asked whether the sand production prediction model-software packages has been evaluated by actual field test and how about its probability success. AL-KAABI said for NASPRO- the finite element model is evaluated in laboratory and as shown from the CT scan images, the model predicted the failure of the onset of sanding. For the other package-SANDRO was validated with field data. However because of the amount of data and availability of data it will always be like: complete data may have successful evaluation. E. C. GRIFFITH questioned what the main emphasis is going to be for experimentation and actual application of rock mechanics in the next decade compared
Johancsik, C.A. (Esso Resources Canada Limited) | Leraandd, A.E. (Computalog Gearhart Ltd.) | Petovello, B.G. (Computalog Gearhart Ltd.) | Gust, D.A. (Exxon Production Research Company) | Smith, B.W. (Esso Resources Canada Ltd.)
Wellbore position accuracy requirements for Esso Resources' Norman Wells Expansion Project Drilling Program have resulted in the choice of Measurement While Drilling (MWD) as the primary surveying system. The accuracy achieved at Norman Wells using an MWD system is the product of manyfactors. In addition to tool design and calibration, the operating and data check procedures are fundamental to achieving the required accurac-v in the severe magnetic environment at Norman Wells. Introduction Scope of Norman Wells Drilling Program Esso Resources Canada Limited is currently undertaking a major expansion project of the Norman Wells oil field. This field is located in the Northwest Territories on the Mackenzie River, 145 km south of the Arctic Circle (Figure 1). The expansion project includes drilling approximately 162 wells between July 1982 and April 1985. The wells are drilled from mainland and natural island locations and from six artificial islands in the Mackenzie River (Figure 1). Seventy-eight per cent of the project wells are directionally drilled to reach reservoir targets under the Mackenzie River. As of March 31, 1984, 100 of the wells have been drilled.