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Saurbayev, Ilyas (North Caspian Operating Company, now with Shell Kazakhstan) | Reedy, John (North Caspian Operating Company) | Bukharbayeva, Aigerim (North Caspian Operating Company) | Hatiboglu, Can (North Caspian Operating Company) | Massingill, Amber (North Caspian Operating Company)
Abstract This paper presents the use and value of information obtained from interference testing performed during the early production of Kashagan field. Numerous field examples of the interference and pulse tests are presented along with their implications for improving reservoir characterization and modeling. Design aspects of the conducted tests and an approach to address uncertainties in the pressure data are also described. A significant amount of important interference data was captured during the start-up and subsequent ramp- up of Kashagan field. This included local well to well interference and pulse testing as well as an extended test that covered a larger area of the field. However, operational activities at observer wells complicated the available data and necessitated application of a pressure correction methodology. This methodology had to account for the inherent uncertainty in the interpretation of the data. Moreover, to increase our confidence in the interpretation, a dedicated pulse test was performed in the specific part of the field. Finally, responses from all observation wells were integrated and analyzed to capture big picture learnings from the early interference testing program. When results of the interpreted interference response from all observers were combined, several groupings of wells became apparent. This helped to understand the degree of connectivity in various areas of the field. For dynamic model calibration, it was preferable to have a range of interference responses for each well to reflect uncertainty in the data. Therefore, so called "early" and "late" response curves were developed for each well. Overall, the collected and analyzed interference data was very useful in reducing uncertainty during this early period and will be used to optimize reservoir management decisions and future phases of the field development. Results presented in this paper can be used by practicing engineers as another great example for advocating the use of permanent downhole gauges (PDHGs) and importance of proper planning and execution for the interference and pulse tests.
From liability to cost effective data gathering opportunityThe revival of a twenty year old exploration well
By Edwin Quint, Candy Beck Brake, John Bickley, Bud Johnston and Paul Huckabee Shell Americas
Commercial production from micro-Darcy reservoirs has only been established recently as a result of advances in hydraulic fracture technology. Little is known about reservoir pressures, drainage areas and recovery efficiencies in these ultra tight reservoirs all of which impact optimal field development and well spacing. Improperly developing a field based on incorrect assumptions about drainage area can be costly.
The Pinedale anticline in the Green River Basin, Wyoming, is an example of this type of reservoir. The producing formation is a thick section of fluvially deposited Lance formation that has over 5000 feet of gross thickness but only an average permeability of 5 micro-Darcy. Pressures vary considerably from the top of the producing formation to the base. Unfortunately direct accurate pressure measurements have been difficult to obtain with the standard wireline tools due to the extremely low permeability.
Many wells were drilled into the Pinedale gas accumulation prior to establishing commercial production. These wells were viewed as a liability given the need to plug them but one of the wells was given a ?second life? as pressure monitor well and will now provide data for years even after its abandonment. To address the spacing issue other operators have drilled closely spaced wells to monitor production interference between producing wells. However, in an area with complex geology it may take years to see interference and it will be difficult to distinguish it from compartmentalization. Pressure changes between wells would occur much sooner and would be more conclusive. However, most operators are reluctant to drill new wells that cannot be put on production immediately. Therefore the old wells provide a unique cost effective opportunity for long term pressure monitoring.
Instead of abandoning an old well with a few plugs an abandonment with multiple permanent plugs with pressure gauges below them and a wireless communication system can be used to transmit pressure data to the surface for years after abandonment. In addition to giving indications of depletion, these gauges provided the first reliable initial pressure data for Pinedale.
Abstract This paper considers different mechanisms of well-to-well interference in low permeability reservoir systems, but focuses specifically on the hydraulic fracture well-to-well interference (commonly referred to as frac-hits) in the Haynesville shale. While well-to-well interference induced by hydraulic fracturing is a very common type of event in this play, such interference is sometimes overlooked as it often results in production gains for the well impacted by the fluids injected during an offset well stimulation treatment. The objective of this study is to maximize the use of the production data available from the well-to-well interference incidents (a simple, low-cost surveillance strategy) to characterize, quantify, grade, and to understand the causes and consequences of hydraulic fracturewell-to-well interference in order to continue to optimize the development of the field in terms of its economic value. In this paper we first introduce the different types of well-to-well interference as background before the focus shifts into the hydraulic fracture well-to-well interference. The methodology begins with characterizing, quantifying, and ranking 65 historical frac-hit events that were documented in the Haynesville shale. Following this effort, we describe the findings as to what causes a frac-hitevent and what drives the magnitude and extent of the production interference. The analysis of field data lead us to the relatively simple observation that a pressure sink (i.e., an area of depleted pressure) is not only the main cause, but it is also a necessary condition for a significant frac-hit to occur. Data suggests the degree of well communication highly correlates to the magnitude of the pressure sink and the distance between the producer and the infill well. Regarding the well performance implications for the " parent" wells in the Haynesville shale, some wells do experience severe wellbore damage from a given frac-hit (or sequence of frac-hits). Although cases of severe damage are notthe focus of this paper, we include insight about such cases and we direct the reader to other sources of information. An obvious comment would be that frac-hits which cause damage are considered to be negative. However, for the majority of the cases reviewed in this paper, the parent wells affected by frac-hits are able to continue to produce — andthe post-frac-hitimpact varies from neutral to positive both in terms of short-term production gains and long-term recovery.
Ji, Qin (Reveal Energy Services) | Vernon, Geoff (Earthstone Energy) | Mata, Juan (Earthstone Energy) | Klier, Shannon (Earthstone Energy) | Perry, Matthew (Reveal Energy Services) | Garcia, Allie (Reveal Energy Services) | Coenen, Erica (Reveal Energy Services)
Abstract This paper demonstrates how to use pressure data from offset wells to assess fracture growth and evolution through each stage by quantifying the impacts of nearby parent well depletion, completion design, and formation. Production data is analyzed to understand the correlation between fracture geometries, well interactions, and well performance. The dataset in this project includes three child wells and one parent well, landed within two targets of the Wolfcamp B reservoir in the Midland Basin. The following workflow helped the operator understand the completion design effectiveness and its impact to production:Parent well pressure analysis during completion Isolated stage offset pressure analysis during completion One-month initial production analysis followed by one month shut-in Pressure interference test: sequentially bringing wells back online Production data comparison before and after shut-in period An integrated analysis of surface pressure data acquired from parent and offset child wells during completions provides an understanding of how hydraulic dimensions of each fracture stage are affected by fluid volume, proppant amount, frac stage order of operations, and nearby parent well depletion. Production data from all wells was analyzed to determine the impact of depletion on child well performance and to investigate the effects of varying completion designs. A pressure interference test based on Chow Pressure Group was also performed to further examine the connectivity between wells, both inter- and intra-zone. Surface pressure data recorded from isolated stages in the offset child wells during completions was used to resolve geometries and growth rates of the stimulated fractures. Asymmetric fracture growth, which preferentially propagates toward the depleted rock volume around the parent well, was identified at the heel of the child well closest to the parent. Fracture geometries of various child well stage groups were analyzed to determine the effectiveness of different completion designs and the impact of in situ formation properties. Analysis of parent well surface pressure data indicates that changing the completion design effectively reduced the magnitude of Fracture Driven Interactions (FDIs) between child and parent wells. Child well production was negatively impacted in the wells where the fracture boundary overlapped with the parent well depleted volume in the same formation zone. This study combines pressure and production analyses to better understand inter- and intra-zone interference between wells. The demonstrated workflow offers a very cost-effective approach to studying well interference. Observing and understanding the factors that drive fracture growth behavior enables better decision-making during completion design planning, mitigation of parent-child communication, and enhancement of offset well production.
Depletion effects occurs in unconventional reservoirs when the hydraulic fractured wells are completed within the drainage volume of existing producers. Field production and monitoring data show that the existing (parent) wells negatively affect the new (child) wells' productivity, making the new wells produce less than if all the wells are drilled and produced at the same time. This paper presents a systematic study on quantifying the offset well depletion effect in the Permian basin through advanced reservoir modeling and data analytics from field pilots.
The workflow starts with building an Earth model for parent wells in the area of interest, generating a hydraulic fracture network, and performing reservoir simulation for production forecast. The depletion effect, including changes in geomechanical properties on child wells, is properly updated in the Earth model and further captured through fracture geometry distortion and production decrease in the depleted environment. The results from the simulation models are further validated with actual field data. Simulations and pilot studies in both Midland and Delaware basins demonstrate that offset well depletion effect can have significant impact on production performance.
The ability to quantify depletion effect has significant business impacts on development sequence, facility design, completion design, and overall project economics. Analysis on various development scenarios was performed to evaluate the economic impact of depletion effect and determine how to mitigate this effect. Net present value (NPV) economic analysis of different simulation results indicates that time duration of production in the parent well ahead of child well has more impact on depletion effect than the distances between parent and child wells. As examples, depletion quantifications are applied to optimize well production near lease boundary with parent well depletion on the competitor land and guide section development strategy by evaluating pad sequence scenarios.