Formation consolidation is a form of sand control that was used extensively in the past, but has been largely replaced by mechanical systems, such as gravel packs or expandable screens. This change has arisen because of a level of uncertainty regarding effective chemical placement and reliability. Challenging economics in the petroleum industry began to make alternative completion techniques more attractive for remediation applications, for developing and producing by-passed reserves behind blank pipe, and for completing marginal reservoirs. Low-cost completion alternatives are actively being sought for both injectors and producers. To understand the performance of various consolidation options, a series of tests was performed on samples of Castlegate sandstone, incorporating actual perforating operations in the lab to evaluate both treatment placement and performance under reservoir conditions. This paper provides details about the testing process that was used, as well as comparative results for various consolidation technologies, including curable and non-curable agents resulting in various degrees of cohesion between formation particulates. Post treatment evaluations included flow testing single and dual phase fluids under in-situ conditions, as well as post mortem evaluations of chemical placement and mechanical properties. Section IV perforation flow testing provided a realistic modeling technique to understand the effectiveness of a consolidating agent with respect to its placement or coating behavior, which in turn directly affects the resulting strength and retained permeability after chemical treatment. Results from the flow testing indicate that a critical strength is required to lock the treated sand in place and to overcome the drag force generated by flow. Depth of treatment penetration into the formation matrix is a function of treatment volume, pressure drop, and permeability. The amount of consolidating agent coating on the sand and the resulting strength depend on the concentration of the agent in the treatment solution. With efficient strength as a result of the consolidating agent treatment, only a small quantity of sand was observed to produce from the treated perforation, either with single or dual phase fluids, when compared to a much larger amount of sand produced from the perforation that lacked treatment, even when the perforation was subjected to a lower flow rate. Introduction Resin treatments are a form of sand consolidation used for sand control since the 1950s. Sand consolidation includes many appealing features, such as the elimination of complex completion equipment and pumping operations that are associated with conventional sand control completions using gravel pack or frac pack technologies. One of the primary concerns with sand consolidation has been the effective placement of the chemical treatments into the reservoir, especially when longer reservoir sections are exposed to the wellbore. Today, consolidation is used in a limited number of completions, typically when exploiting up hole by-passed reserves or in remediation applications where sand production becomes problematic only after water breakthrough in a wellbore. When wells are in the later stage of life and beginning to produce water, and thus produce an inflow of sand, they may become good candidates for sand consolidation treatment. It is always beneficial to physically simulate the merits of a new concept for well applications, when possible. Packed cylinders and Hassler core holders have been used to begin the process of evaluating consolidation system potential. In this case, a replicated wellbore with a perforation tunnel into semi-friable sandstone was used to perform a series of formation consolidation tests to evaluate the properties pertinent to what is considered a successful treatment. These properties include rock consolidation strength, depth of treatment, and post treatment permeability.

API RP 19B Section 4 tests were established to evaluate perforator performance at field conditions. The question of how well such a small-scale laboratory test translates to downhole reality has long been raised. Furthermore, how accurately are downhole dynamics reproduced in single-shot, Section 4 tests, when in practice, an extensive formation is perforated with multiple shots?To address this question, flow fields for typical axial and radial API Section 4 flow targets were calculated using a general analytical model based on potential theory and compared with the calculated results of various downhole configurations with different shot densities. When compared with calculations of downhole flow, we show that both radial and axial API targets can yield flow patterns that differ considerably from those downhole, which could lead to erroneous interpretations of results and dynamic effects, such as cleanup. As expected, results show that a radial flow target tends to overestimate the flow into a downhole perforation depending on the shot density and that an axial flow target tends to underestimate the flow depending on target length.We discuss how to modify the API test core by attaching a low-permeability sleeve to create a more accurate downhole flow simulation. The result is a more representative test that better reproduces the initial static reservoir pressure and the postshot flowing pressure.To illustrate the concept, we made several tests using modified and unmodified axial flow targets to compare flow efficiency through perforations. Initial results indicate a difference in flow between the two sets of targets, with the modified targets having lower flow efficiency. Finally, we offer some possible physical reasons to explain the difference.

The nature of the crushed zone is important to the overall hydrocarbon flow following perforation. This work examines the nature of such formation damage using testing and simulation. Furthermore, the crushed zone's effect on overall formation productivity is also discussed. Using a shock hydrocode, the crushed zone is compared and contrasted by thickness and density for deep penetrating (DP) and big hole (BH) charges. The results are compared to information obtained from flow-laboratory-created crushed zones from previous perforation tests. Information from flow-laboratory testing is then used as input to model flow through the crushed zone and hence measure permeability. A study of the relative effect of the crushed zone on skin effects, including its relative contribution to the overall perforation skin, is presented. Simulation results indicate that the crushed zone from a DP charge is much thinner than the BH charge layer. These results are obviously charge dependent (in the same class). Visual observations show a structure that differs in the crushed zone from the ambient zone around the perforation. A flow model is derived, which accounts for the transition of hydrocarbon flow through the crushed zone. The crushed zone results are then considered in overall flow production, demonstrating when its effect becomes applicable. These results are reflected in a charge penetration code. Combining all of the information, a recommendation is made to help achieve optimal production downhole.

Several recently introduced oilfield perforators incorporate reactive materials that are derivatives of military-based weapons technology. Claims have been made that reactive shaped charges provide improved downhole performance and well productivity over conventional shaped charges by creating optimized perforation tunnels. To better understand and quantify differences in penetration and flow performance between reactive shaped charges and conventional shaped charges, we designed a test matrix that takes into account various environments, such as gas in low permeability rock and oil in higher permeability rock. The performance assessments of reactive vs. nonreactive perforators were performed under controlled conditions in an API Perforation Flow Laboratory (PFL) (API 2006). The tests, which involved shooting into stressed rock under simulated downhole conditions, were conducted in Berea Sandstone targets with mineral oil flow to simulate a typical oil-bearing formation, and in Carbon Tan Sandstone with nitrogen flow to simulate a typical gas-bearing formation. The Berea Sandstone represented moderate-to-high porosity and permeability rocks with high, unconfined compressive strength (UCS). The Carbon Tan Sandstone represented low-permeability and medium-porosity rocks with moderate UCS. To further understand the contribution of the reactive component, tests were performed in balanced, underbalanced, and overbalanced conditions. Charge performance measurements were taken for both conventional and reactive charges in each target reservoir rock. This paper describes the methodology used for the comparative tests between reactive and nonreactive perforators in the Berea Sandstone portion of the program and summarizes the observations of core penetration, clean up, and productivity. Introduction The API Recommended Practices for evaluating well perforators (API 2006) provides an essential protocol for measuring and quantifying the effects of changes to shaped-charge perforators designed for increasing penetration and flow performance. Laboratory simulation of a downhole perforating event involves detonating a single shaped charge into a stressed porous media using a hardware configuration that is similar or equivalent to that used in the wellbore. In this study, three different reactive charges and one conventional charge, all under the sub-grouping of deep penetrators (DP), were shot into two sets of downhole-configured targets, and the penetration and flow performance were compared. Three borehole conditions were simulated for each of the four charges: underbalance, balance, and overbalance. For statistical validity and verification, the test for each borehole condition was repeated three times and independently witnessed, resulting in a total of 72 tests. To replicate downhole perforating conditions, the setup consisted of commercially available 3-3/8-in. deep-penetrating shaped charges (listed in Table 1) that were shot from inside a pressurized wellbore using a simulated single-shot perforating gun, through a simulated scallop, fluid gap, casing plate, cement sheath, and into the formation-analog rock. Phase I used a stressed Berea Sandstone core filled with odorless mineral spirits (OMS), and Phase II used a stressed Carbon Tan Sandstone filled with nitrogen (Table 2). The acquired data include, but are not limited to, depth of open perforation tunnel, depth of total perforation penetration, the perforation geometry, hole diameter in casing and cement, flow performance, flash radiography images, and time vs. pressure traces (Appendix A), as well as statistics on significance (Appendix B), CT scans (Appendix C), and thin sections of the perforation tunnel walls (Appendix D).

This paper describes the results of rock and fluid property measurements and of the reservoir simulations associated with the demonstration of CO2-assisted oil recovery in the Cypress Sandstone reservoirs at Mattoon Field, Illinois. This work provided technical support for the field project. Results from core flood tests indicate that oil recovery from immiscible displacement of reservoir crude oil with carbon dioxide will increase with displacement pressure. Miscible displacement of oil with CO2 from the Cypress Sandstone reservoirs at Mattoon field is not possible. As shown by the slim-tube experiments, the minimum miscibility pressure (MMP) of Mattoon oil is close to the formation parting pressure of the Cypress Sandstone at Mattoon field. Nevertheless, phase behaviour experiments show that dissolved CO2 significantly enhanced oil recovery through oil swelling and viscosity reduction at pressures below miscibility conditions. Numerical simulations of CO2 injection into various reservoirs within the Sandstone were performed. A straight CO2injection program and a water alternating gas (WAG) injection program were simulated and compared in both the A-sandstone of the Pinnell Unit and E-sandstone interval of the Sawyer Unit. In the Pinnell Unit, the simulated results show an inefficient displacement of reservoir oil by CO2 and that neither of the two methods will be economically feasible because of the poor interwell communication and limited areal extent of the producing interval. This result is supported by the low oil recovery from the field CO2 injectivity tests in the Pinnell Unit. On the contrary, simulated results show that a significant amount of additional oil can be produced from the Sawyer Unit. The wateralternating- gas (WAG) injection program yielded more oil than water injection alone. The simulated results also indicate strategically- placed new wells will enhance the recovery of additional oil. Introduction This work provided technical support for a CO2-assisted oil recovery demonstration project funded by a cost-shared agreement (Cooperative Agreement number DE-FC22-93BCI4955) between the United States Department of Energy and American Oil Recovery, Inc. (AOR). The Mattoon Field, which is the site of the project (Figure 1), was discovered in June 1940. Development included approximately 420 producers and 90 dry holes drilled on a 4.05 ha (10 acre) well spacing. The principal reservoirs are found in the Cypress, Rosiclare and Aux Vases Sandstones of the Mississippian System (Figure 2). Secondary recovery was initiated in 1952 utilizing Pennsylvanian brine as well as treated municipal sewage water(1). The target intervals for additional oil recovery with CO2 are the Chesterian Cypress Sandstone reservoirs in the Mattoon field. In general, Cypress Sandstone reservoirs are the most prolific in Illinois(2). Recent studies(3,4,5) show that Cypress reservoir sandstones consist of four to five stacked layers having varying reservoir quality and often separated by thin shaly sandstone or calcareous beds. Because of the variations in reservoir quality, some layers are not as efficiently swept as others during water flooding. Such layers will contain more bypassed mobile oil than others. Furthermore, Cypress Sandstone reservoirs typically have high immobile oil saturation.