Decline curve analysis is widely used in industry to perform production forecasting and to estimate reserves volumes. A useful technique in verifying the validity of a decline model is to estimate the Arps decline parameters, the loss ratio and the b-factor, with respect to time. This is used to check the model fit and to determine the flow regimes under which the reservoir produces. Existing methods to estimate the b-factor are heavily impacted by noise in production data. In this work, we introduce a new method to estimate the Arps decline parameters.
We treat the loss ratio and the b-factor over time as parameters to be estimated in a Bayesian framework. We include prior information on the parameters in the model. This serves to regularize the solution and prevent noise in the data from being amplified. We then fit the parameters to the model using Markov chain Monte Carlo methods to obtain probability distributions of the parameters. These distributions characterize the uncertainty in the parameters being estimated. We then compare our method with existing methods using simulated and field data.
We show that our method produces smooth loss ratio and b-factor estimates over time. Estimates using the three-point derivative method are not matched with data, and results in biased estimates of the Arps parameters. This can lead to misleading fits in decline curve analysis and unreliable estimates of reserves. We show that our technique helps in identification of end of linear flow and start of boundary dominated flow. We use our method on simulated data, with and without noise. Finally, we demonstrate the validity of our method on field cases.
Fitting a decline curve using the loss ratio and b-factor plots is a powerful technique that can highlight important features in the data and the possible points of failure of a model. Calculating these plots using the Bourdet three-point derivative induces bias and magnifies noise. Our analysis ensures that this estimation is robust and repeatable by adding prior information on the parameters to the model and by calibrating the estimates to the data.
Complex Toe-to-Heel Flooding (CTTHF) is a short distance flooding technique developed by the authors for sandstone formations. CTTHF applied on horizontal wells and requires at least one barrier and injector hydraulic fracture, also it requires at least one method to control early water production. This paper discusses the design aspects of the CTTHF including the design of barrier fracture, injector fracture, and the produced water control methods. Technical and economical evaluation to rank different design setups is performed and presented.
Advanced commercial reservoir simulator with hydraulic fracturing module was used to simulate different CTTHF setups and reservoir conditions to set the reservoir selection criteria and proper design methodology. In this study, Toe-to-Heel Waterflooding was considered the base case. Sensitivity studies for barrier fracture and injector design has been achieved and presented. Moreover, a sensitivity studies for hydraulic fractures spacing, number of barrier fractures, batch injection scheduling and changing packer location have been performed.
When CTTHF is applied in high permeable sandstone formation, early water production is expected, except produced water control method is used. This study states the feasibility conditions for each proposed produced water control technique. Also, a methodology for candidate reservoir selection, design of barrier and injector fractures is developed and presented. There are multiple fluid systems can be used to create the barrier to seal a pre-determined zone. CTTHF is better reservoir management approach.
The novelty of the CTTHF is giving multiple options for produced water control that maximizes the produced oil and minimizes the water production. CTTHF's produced water control can make some reservoirs economic to produce.
Albert, Larry (Allied-Horizontal Wireline Services) | Booher, Jason (Allied-Horizontal Wireline Services) | Wilson, Anthony (Allied-Horizontal Wireline Services) | Hamilton, Fraser (Impact Selector International) | Hradecky, Jason (Impact Selector International) | Dunning, Dustin (Wireco WorldGroup) | Pratosov, Vadim (Wireco WorldGroup)
An E&P operator was developing a reservoir and planned a horizontal well in an area where zones above the target cause drilling problems when trying to build angle and land the horizontal lateral. The operator suffered drilling difficulties on offset wells; therefore, it was decided to change the drilling plan for this prospect. The new plan required drilling through the target reservoir, into the formations below and then drill back up dip to the target. After reaching the base at a measured depth of 14,000 ft. the well plan required drilling up at maximum of 114° until reentering the target reservoir. Because of faulting in the area and required well direction, the target reservoir was dipping up at ∼10° laterally in the direction of the horizontal drilling target. To maintain position in the reservoir, the well had to drilled at ∼100° deviation to a measured depth of 21,100 ft.
This wellbore trajectory made normal wireline plug and perforating completion operations extremely difficult. The wellbore trajectory meant high frictions on the wireline when coming off bottom. Also, due to the toe-up trajectory there was risk the wireline tools would slide down the inclined casing during and after plug setting and perforating. If the tool position could not be maintained there was risk the wireline cable could be entangled and a stuck tool could result. If the tools overrun the wireline cable the result could be wireline cable next to the perforating guns when detonated and wireline cable severed. The E&P operator needed to know if this challenge could be met.
Alternatives to pump down plug and perforating could be very expensive (estimated $millions): Abandon acreage, Continue drilling attempts building angle above the target, Reposition surface location and drill down dip, Reduce angle and shorten lateral in target, or Coiled tubing conveyed plug and perforating completion.
Continue drilling attempts building angle above the target,
Reposition surface location and drill down dip,
Reduce angle and shorten lateral in target, or
Coiled tubing conveyed plug and perforating completion.
To meet the challenge several new methods and technologies developed for extended laterals were utilized. These products and methods included: advanced risk deployment modeling, jacketed wireline cable, addressable separation tool and downhole tension tool.
Field development strategies in unconventional shale reservoirs have increased in intensity over the last few decades. Completion design and well spacing have been key focus variables in the incremental design process. With this wide range of design and development strategies, assets across different basins might end up with wells from a variety of design generations. This could make type curve creation even more complicated as it does not account for impact of hydrocarbon drainage in an area by the older (parent) well on the newer (child) wells. The present paper tackles this issue by addressing type curve development by including date dependent spacing variables to account for the dynamism of field development strategies over the years.
The present paper analyzes the impact of well spacing on type curve development in an asset. Type curve generation is a critical component in evaluation and subsequent planning so de-risking this step is very valuable. A lot of the analysis done in recent years is by considering well spacing as a static variable. The present analysis looks at spacing as a dynamic variable instead to account for time-series based variations. The spacing in the estimation process is also a 3-D spacing algorithm which identifies multiple points along the lateral section of the wellbore for a true evaluation of pressure transient propagation.
The present analysis showed the impact of date dependent well spacing on type curve development. The underestimation of well spacing in well-developed acreages was brought to attention as spacing mean deviations of upto 0.7 Standard Deviation were found between current well speacing and date-dependent well spacing scenarios analyzed. These deviations led to the type curves having upto a 40% EUR differential between estimation processes, with PV10 differentials higher than 100% in some cases. While the degree of impact of time series well spacing varied across the assets evaluated, quantifying the risk in type curve development and subsequent EUR estimation were key conclusions from the analysis.
The present paper presents a novel approach in tackling type curve development for parent and child wells observed across different basins. The paper provides guidelines on creating highly accurate type curves and highlights errors that may arise due to high well density and inter-well interaction by conducting the analysis in the high well density Middle Bakken formation.
Drilling in the Appalachian basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs, as well as drive efficiency. This paper presents a case study in which offline cementing helped improve operation efficiency by reducing drilling times and provided significant cost savings.
Offline cementing is not a new concept. In Q4 2015, an operator drilling in the Eagle Ford shale began the movement of their program toward offline cementing of both the surface and production casings. The operator determined that reducing flat time was crucial to create a cost savings (
The service company was able to cement both the surface and intermediate casing strings offline while the operator skidded to the next well to begin rigging up. All surface casings were drilled and cemented offline and the rig skidded back to drill for the intermediate casings, which were also cemented offline. Approximately 15 hours was saved by skidding between surface strings, and another 16 hours was saved between intermediate casings.
This paper discusses the successful use of offline cementing during drilling operations in northeastern Pennsylvania. The flat time reduction achieved during this drilling program can be quantified into a cost savings of approximately USD 80,000 per well.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Lian, David (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute For Scientific Research)
It is not easy to obtain an optimal hole cleaning for the drilling operation because of the complicated relationship between the drilling parameters influencing hole cleaning. The two viscosity components (e.g. plastic viscosity (PV) and yield point (YP)) and the flow rate (Q) are essential parameters for effective hole cleaning. Thus, understanding the relationship between those parameters will contribute to efficient hole cleaning. The aim of this paper is to explore those relationships to provide optimal hole cleaning.
Descriptive data analytics was conducted for data of more than 2000 wells drilled in Southern Iraq. The data were first cleansed and outliers were removed using visual inspection and box plots. The Pearson correlation (PC), a widely used method to measure the linear relationship between two parameters, was utilized to access the relationships between PV and Q, YP and Q, and YP/PV and Q. Moreover, a 10% sensitivity analysis was escorted to quantify and comprehend those relationships.
The PCs were calculated to be 0.5, 0.076, and 0.22 for the relationships between YP, PV, and YP/PV with Q, respectively. YP had the highest direct relationship with Q, while PV had the lowest. When the YP increases, a sufficient Q has to be provided to initiate the flow and maintain the mud cycle. In addition, to prevent large solid particles from settling due to the slip velocity, sufficient annular and particle velocities have to be achieved. After initiating the flow, an increase in flow rate to overcome resistance due to PV will not be significant. Therefore, YP has more effect on Q than PV. To maximize hole cleaning, thickening ratio (YP/PV) should be increased. This requires an increase in flow rate, which can be quantified by using the sensitivity analysis provided to achieve the required Q for any increase in YP/PV.
Operators continue their quest to better understand and design completion strategies to maximize reservoir contact and optimize well spacing. This paper presents a case study that analyzes completion design effectiveness, using pressure data acquired from isolated monitor stages on offset wells during treatment of adjacent wells. The method was employed on three wells of a seven-well pad in the Marcellus, to assess fracture growth and evaluate the performance of employing intra-stage and inter-stage diversion.
Poromechanically-induced pressure responses on isolated monitor stages on offset wells during treatment of an adjacent well, are compared to a fully coupled, three-dimensional, finite element effective stress model, to calculate dominant fracture geometries that correspond to the pressure response induced in the rock. The initiation points and ascending magnitudes of the responses approaching the isolated monitor stage qualify the performance of inter-stage diversion, whereas the fracture growth trends and geometries speak for the efficacy of the intra-stage diversion and overall stage design.
The first well utilized inter-stage diversion and dissolvable plugs to isolate stages; the second well utilized intra-stage diversion to improve cluster efficiency with regular frac plugs for zonal isolation; and, the third well employed regular frac plugs with no use of diversion. This presented a unique opportunity to compare and analyze the fracture growth rates, trends, and geometries, while applying inter-stage diversion and frac plug completion designs for zonal isolation on the same pad.
This paper is a comparative study to understand the value of using inter-stage diversion, along with dissolvable plugs in place of composite frac plugs, after every stage to attain zonal isolation. In addition, completed stages utilized different fluid designs, providing the opportunity to analyze the impact of fluid design on fracture growth trends and diverter performance. The results are interpreted using pressure data-derived fracture maps with production data, which point to the performance of various completion strategies, using an entirely new diagnostic method.
Improved completion design and field development strategies have provided commodity price resilience by sustained efficiency gains across most major US Shale plays. This rapid evolution in completion practices, however, has created behind pipe opportunities. Refracturing offers a viable solution to maximize on these opportunities, however, its effectiveness is dependent on a variety of factors. The present paper explores the implementation of refracturing as a re-development strategy in legacy shale plays and evaluates it as a truly multivariable problem.
The paper takes into consideration petrophysical parameters, initial completion design, chemical composition, formation quality, time from original completion, refrac completion design and production performance to quantify impact on refrac KPIs such as IP ratio, EUR ratio, decline trend impact, amongst others. The paper does this by using an ACE (alternating conditional expectation) non-linear regression model that incorporates the KPI’s as response variables and utilizes the transforms of a wide range of input variables to identify cause and effect relationships. By running this analysis across multiple legacy shale plays, including the Haynesville, and Barnett, the paper provides best-practices to maximize refracturing success.
While refrac can offer a viable solution in obtaining incremental production, depending on the basin, a refrac can be a tenth of the expense of a new well and can beneficially impact the production from the existing well. In most cases, the analysis found EUR predictions improved by 30% - 200%. While correlations varied across basins and completion design, an inverse correlation was found between refrac KPIs and initial frac intensity.
Although, refracturing in horizontal shale wells is a well-established practice, a significant amount of analysis on their performance is focused on one or two key variables. The present paper adds to the existing body of literature by using data analytics and machine learning to evaluate this strategy from a truly multivariable standpoint. The paper also provides best practices to evaluate and predict refrac performance to de-risk refrac as a field re-development strategy.
This paper presents a method for pinpointing intervals for fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. Out of the more than 60 wells studied, wells exhibiting minor changes in the d-exponent showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile and the negative impact of equal space fracturing.
The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.