Waterflood Wells Research Articles

Optimal control of multilateral waterflooding wells in carbonate reservoirs with uncertainty consideration

The benefits of adjoint formulation in studying and improving the economic and production viability of reservoir waterflooding problems has been reported in several researches. However, there is little or no recorded report on its use for multilateral wells in uncertain waterflood reservoir conditions. This study aims to investigate the effect of geological uncertainty to multilateral well performance using adjoint formulation in oil reservoir waterflooding. First, an oil reservoir model with uncertainty assumption in permeability, Corey value, and physical dimension in reservoir compartmentalization was developed. Second, an optimal control sequence for the multilateral injection well was developed to optimize the net present value (NPV). The study revealed that with the obtained control sequence, reservoir compartmentalization notably faults in rock structure, significantly influenced the production capacity of multilateral wells which resulted in a higher NPV and oil rate when compared to other uncertainty cases.

Analysis of Cement Sheath–Rock Damage Mechanism—A Case Study on Water Injection Wells

In the field of water injection wells within oilfields, comprehending the intricate mechanics of water channeling and the resulting rock damage on the external cemented surface holds paramount significance for the efficient management of reservoirs. This paper presents a comprehensive study aimed at illuminating the complex nature of rock damage on the external cemented surface of casings and deciphering the underlying mechanisms that underpin water channeling occurrences. To this end, a robust constitutive model is established and refined to capture the multifaceted interactions inherent in rock damage on the cemented surface. This model introduces a modified bonding force approach to enhance shear stress precision and thoughtfully accounts for the profound effects of elastic–plastic behavior, cracking damage, and elastic-cracking coupling damage on damage progression. Subsequently, the refined model is employed to investigate rock damage on the external cemented surface of water injection wells, encompassing variations in confining pressure, rock width on the cemented surface, and the ratio of Young’s modulus between the cement sheath and the rock. The research findings emphasize the interplay between cracking and elastic damage as the catalyst for rock damage on the cemented surface. Impressively, the accuracy of the refined constitutive model for the cemented surface has advanced by over 5% compared to prior studies. The manipulation of confining pressure and the Young’s modulus ratio enhances peak fracture water pressure, signifying substantive strides in comprehending damage propagation mechanics. Furthermore, the study discerns the negligible influence of rock width on the cemented surface regarding damage patterns. These findings have important implications for the effective management of water injection wells, providing insights for the restoration of water channeling wells and proactive measures against water channeling phenomena. They also contribute to the refinement of well cementing practices and the proficient management of water channeling and water flooding in oilfields. The research findings have profound implications for the domain of water injection wells, offering novel insights into the restoration of water channeling wells and the implementation of preemptive measures against water channeling phenomena. These findings hold the potential to guide the refinement of well cementing practices and the adept management of water channeling and water flooding wells within the studied oilfield.

Optimization Control of Oilfield Waterflooding Systems Based on Different Zone and Pressure

The scrapping of old waterflooding wells and the increase in new waterflooding wells results in mixed flooding of high–low pressure wells in various oil layers in waterflooding systems. In order to meet production operation requirements, the whole system is in a state of high pressure, which leads to an increase in energy consumption and complicates the operation of waterflooding networks. According to the pressure distribution of wells, proceeding with regional accurate waterflooding can reduce operation costs and improve development efficiency. Considering the technical constraints of waterflooding networks, a method was proposed, which can quantitatively optimize classification and zoning for waterflooding of high–low pressure wells according to the pressure of networks and wells. At the same time, the ant colony algorithm and genetic algorithm were fused to form a new adaptive ant colony genetic hybrid algorithm, which can effectively determine the best pumping scheme of the waterflooding station, the pumping flow and optimize the low-pressure area. The K-means algorithm was used to optimize the topology of the pipe network in the high-pressure area to reduce the overall waterflooding pressure. Finally, the method was successfully applied to the large-scale waterflooding system including 2200 wells and 10 waterflooding stations in sites in China. The results show that the method is effective for the operation and reconstruction of waterflooding pipe networks with large-scale and serious mixed high–low pressure.

Injection profiling in horizontal wells using temperature warmback analysis

Horizontal wells have been used for water flooding operations for the purpose of pressure maintenance and improved oil recovery, e.g., in tight oil reservoirs. Injection profiling along the well lateral is required to determine the effectiveness of water flooding operations and to maintain high sweep efficiency. Recent improvements in downhole temperature monitoring tools allow monitoring the transient temperature along horizontal waterflooding wells at a relatively low cost. Temperature data can be analyzed to infer the injection profile along wellbore and locate high permeability regions that cause non-uniform rate distribution along the wellbore. In this work, an analytical model is developed to describe the transient temperature in the reservoir during cold fluid (water) injection via a horizontal well during injection and warmback periods. The analytical solution assumes linear flow in the reservoir and accounts for heat transfer by different mechanisms including convection, conduction, and heat gain from the surrounding impermeable strata. The inversion procedure is introduced to evaluate injection profiling using analytical solution–based type curves. Different cases are considered using a thermally coupled numerical reservoir simulator to verify the analytical approach and illustrate the potential application of the inversion technique. We show that the analytical approach introduced in this work is an efficient and robust technique to infer the injection profile along horizontal wells.

Reservoir Compartmentalization Caused by Mass Transport Deposition, Northwest Stevens Pool, Elk Hills Naval Petroleum Reserves, California: ABSTRACT

The [open quotes]A[close quotes] sands of the Northwest Stevens Pool consist of six major subdivisions (A1-A6) and numerous sublayers. These sands are above the [open quotes]N Point[close quotes] stratigraphic marker, making them much younger than most other Stevens sands at Elk Hills. Cores show the A1-A3 sands to be possibly mass transport deposition, primarily debris flows, slumps, and sand injection bodies. The A4-A6 sands are characterized by normally graded sheet-like sand bodies Hospital of traditional outer fan turbidite lithofacies. Most current production from the A1-A2 interval comes from well 373A-7R, are completed waterflood wells that came on line in 1992 at 1400 BOPD. Well 373A-7R is an anomaly in the A1-A2 zone, where average production from the other ten wells is 200 BOPD. Other evidence for compartmentalization in the A1-A2 interval includes sporadic oil-water contacts and drawdown pressures, difficult log correlations, and rapid thickness changes. In 1973, well 362-7R penetrated 220 ft of wet Al sand. The well was redrilled updip and successfully completed in the A1, where the oil-water contact is more than 130 ft lower than the original hole and faulting is not apparent. In 1992, horizontal well 323H-7R unexpectedly encountered an entirely wet Al wedge zone. Reevaluation more » of the A1-A3 and other sands as mass transport origin is important for modeling initialization and production/development strategies. « less

Disposal Well Problems in Chicago and Bakersfield Areas

The disposal of industrial liquid wastes is becoming increasingly important in recent environmental protection activity, and the subterranean disposal of such wastes will receive more attention. As the result of the writer's experience with two such wells, this paper proposes that the consultant for the development of such wells obtain advice from experts in all pertinent disciplines, with well drillers and all suppliers of services and materials for such well construction. Published data on existing water-flood wells in the region can supply approximate predictions of geologic formations suitable for disposal, and probable performance of injection well. The presence of the well designer is required at the well site during construction. Conditions arise demanding instant revision of original design; delay incurs costly driller's waiting time. Aluminum pipe casing window cases off lower capacity disposal zones as reserves for future needs. A combined injection tube and well casing in the form of plastic-lined steel pipe was employed.

Minimization of Scale Deposits in Oil Wells by Placement of Phosphates in Producing Zones

Abstract Deposition of compounds such as calcium carbonate, calcium sulfate and barium sulfate in formation flow channels, on tubing, casing and producing equipment has continuously plagued the oil industry. Although polyphosphates have a long history in scale inhibition, only relatively recently have the extremely slow solubility di-metallic polyphosphates been injected into producing zones in conjunction with fracturing. As a result of such treatments, scale deposition in the formation in addition to the wellbore and producing equipment has been checked in some cases for over a year. Characteristics to be considered when selecting a phosphate for this type treatment have been outlined with the effect each has on scale prevention and on length of time they will be effective. Introduction Mineral deposition in formation flow channels, on tubing, casing and producing equipment has continuously plagued the oil industry. Compounds such as calcium carbonate, calcium sulfate and barium sulfate carried in the produced water may crystallize or precipitate as a result of a pressure drop, a temperature change or exceeding the solubility product. This scaling reduces and sometimes even stops oil production by plugging the formation, perforations or producing equipment. Formation of scale on tubing and producing equipment has been recognized for many years. After extracting this equipment from the well, the deposits have been removed mechanically with scrapers and other such devices. Hydrochloric acid has been found effective when the plugging material is basically carbonate in nature. As early as 1938 and 1939 Krynine and Yuster recognized that these scaling compounds frequently were deposited away from the wellbore in flow channels of waterflood wells. Acid, salts and phosphates were suggested as possible remedial treating chemicals. More recently work has been done which indicates water incompatible with the formation water sometimes can be used in water floods.