Well Productivity Improvement by Chemical Removal of Pyrobitumen

1997 ◽  
Author(s):  
J.C. Shaw ◽  
R. Tsuen ◽  
S.M. Leggitt
Keyword(s):  
Productivity Improvement ◽  
Well Productivity

Well-Productivity Improvement by Use of Rapid Overpressured Perforation Extension: Case History

1996 ◽  
Vol 48 (02) ◽  
pp. 154-159 ◽  
Author(s):  
L. Petitjean ◽  
B. Couet ◽  
J.C. Abel ◽  
J.H. Schmidt ◽  
K.R. Ferguson
Keyword(s):  
Case History ◽  
Productivity Improvement ◽  
Well Productivity

Modeling High-Angle Wells in Laminated Pay Reservoirs

1999 ◽  
Vol 2 (01) ◽  
pp. 46-52
Author(s):  
Phillip S. Fair ◽  
Jitendra Kikani ◽  
Christopher D. White
Keyword(s):  
Gulf Of Mexico ◽  
Line Source ◽  
Semimajor Axis ◽  
Productivity Improvement ◽  
Well Productivity ◽  
Vertical Well ◽  
Vertical Permeability ◽  
Well Model ◽  
Infinite Conductivity ◽  
Bed Thickness

Introduction Productivity improvement and acceleration projects have gained substantially from the success of horizontal well drilling technology. Successful placement of near-horizontal wells in difficult reservoir configurations has become routine. However, not all reservoir situations are amenable to horizontal drilling. Specifically, laminated reservoirs such as thinly bedded turbidites in the Gulf of Mexico (GOM) have been perceived as poor targets. Potentially large reserves are locked in these reservoirs. These laminated turbidite systems have near-zero vertical permeability at the Bouma sequence1 scale and extremely small kv/kh ratios kv/kh?0 at the full field, reservoir simulation grid-block scale. In general, a low well count helps minimize development costs. Highly deviated wells (80∘≤θw<90∘) cutting the entire sand package may make it possible to obtain both high field production rates and low well counts. Slanted wells have been known to improve productivity of wells with kv /kh?0. However, the slanted well model given by Cinco 2,3 does not predict any improvement in well productivity for such wells. This apparent paradox is reconciled in this paper. Bed thickness, well diameter, and well angle determine the geometric pseudoskin of these thin-bedded sequences. For wells that are nearly horizontal, a simple technique is introduced to calculate the geometric skin without complex modeling. The range of validity of this approximation was determined by comparison with fine-grid simulations. This paper provides a method to simulate a highly deviated well in a thin-bedded reservoir at field scale without the use of fine grids or local grid coarsening. These inflow relationships have been used to construct the well models for simulations of GOM reservoirs. A field example is presented with guidelines to determine the correct well kh as validated by a grid sensitivity study. Implications of Existing Slanted Well Solutions Thin-bedded turbidite reservoirs in the deep water Gulf of Mexico are currently being developed.4 These reservoirs are comprised of beds that are on the order of 0.25 in. thick and are separated by very low permeability shales. There are two ways to apply Cinco's2,3 slanted well solution to account for this heterogeneity to determine the potential productivity improvement for slanted wells. The first method treats the entire reservoir as an anisotropic system with zero vertical permeability, whereas the second method considers the thin beds explicitly. However, neither of these methods predict any productivity improvement. For the first method (in which the reservoir is modeled as having no vertical permeability, kv=0), the explanation for no improvement in productivity predicted from Cinco's slanted well solution is trivial. It follows from the definition of the anisotropic angle of slant, which becomes zero (as for a vertical well), for a zero vertical permeability reservoir. In the second method, Cinco's2,3 model is applied separately to each bed and the bed productivities are summed to determine the total well productivity. The productivity improvement due to well angle can be determined by examining Cinco's solution for vanishing bed thickness. Fig. 1 shows the geometric pseudoskin as a function of bed thickness normalized by the wellbore radius for various angles between zero and 88°. These results were generated using Cinco's slanted well solution. As the bed thickness approaches zero, the geometric pseudoskin also tends to zero indicating that the well performance will be unchanged compared with a vertical well. This is true for all deviation angles. The slanted well model generally considers a line source well with flux distributed evenly. To mimic the more realistic infinite-conductivity boundary condition, the uniform-flux solution is evaluated at a particular point on an equivalent wellbore. The particular point is located on the semiminor axis of the ellipse that is defined by the intersection of a horizontal plane with the cylindrical wellbore (Fig. 2). This point is located one wellbore radius away from the line source at a distance of either two-tenths or eight-tenths of the bed thickness from the lower bed boundary. When bed thickness tends to zero and there is no vertical component of flow, the particular point is the same point used to evaluate a line source solution for a vertical well in a porous medium of constant horizontal permeability. Thus, this solution indicates no productivity improvement when compared to vertical wells completed in thinly bedded reservoirs. We offer an alternative limiting solution. Highly Deviated Well Model for Thin Beds The limiting solution we offer considers the wellbore to be represented by a fracture at the bed-thickness level. The "fracture" length is governed by the well deviation angle. The intersection of a slanted wellbore with a bedding plane is an ellipse as depicted in Fig. 2(a). For high deviation angles (80∘≤θ<90∘), the size of this ellipse may be significant. The semiminor axis is rw and the semimajor axis is rw/cos(?). Fig. 2(b) is a plot of ellipses for various well angles. The axes of each ellipse have been normalized using the length of the semimajor axis to illustrate the aspect ratio of the ellipses. For well angles greater than 80°, an infinite-conductivity vertical fracture model that approximates an ellipse seems more applicable than the line source approximation.

Well-Productivity Improvement by Use of Rapid Overpressured Perforation Extension: Case History

1996 ◽  
Vol 48 (2) ◽  
Author(s):  
L. Petitjean ◽  
B. Couet ◽  
J.C. Abel ◽  
J.H. Schmidt ◽  
K. Ferguson
Keyword(s):  
Case History ◽  
Productivity Improvement ◽  
Well Productivity

Well Productivity Improvement Using Radial Jet Drilling

2020 ◽  
Author(s):  
Rahman Ashena ◽  
Reza Mehrara ◽  
Ali Ghalambor
Keyword(s):  
Productivity Improvement ◽  
Well Productivity

Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well

2009 ◽  
Vol 12 (04) ◽  
pp. 576-585 ◽  
Author(s):  
Jitendra Mohan ◽  
Gary A. Pope ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Relative Permeability ◽  
Gas Condensate ◽  
Darcy Flow ◽  
Productivity Improvement ◽  
Well Productivity ◽  
Fracture Width ◽  
Gas Condensate Reservoirs ◽  
The Impact ◽  
Actual Fracture

Summary Hydraulic fracturing is a common way to improve productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than have been actually observed in the field. This paper shows the large impact of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well. Two-level local-grid refinement was used so that very small gridblocks corresponding to actual fracture width could be simulated. The actual fracture width must be used to accurately model non-Darcy flow. An unrealistically large fracture width in the simulations underestimates the effect of non-Darcy flow in hydraulic fractures. Various other factors governing the productivity improvement such as fracture length, fracture conductivity, well flow rates, and reservoir parameters have been analyzed. Productivity improvements were found to be overestimated by a factor as high as three, if non-Darcy flow was neglected. Results are presented that show the impact of condensate buildup on long-term productivity of wells in both rich and lean gas-condensate reservoirs. Introduction A significant decline in productivity of gas-condensate wells has been observed, resulting from a phenomenon called condensate blocking. Pressure gradients caused by fluid flow in the reservoir are greatest near the production well. As the pressure drops below the dewpoint pressure, liquid drops out and condensate accumulates near the well. This buildup of condensate is referred to as a condensate bank. The condensate continues to accumulate until a steady-state two-phase flow of condensate and gas is achieved. This condensate buildup decreases the relative permeability to gas, thereby causing a decline in the well productivity. Afidick et al. (1994) studied the Arun field in Indonesia, which is one of the largest gas-condensate reservoirs in the world. They concluded that a significant loss in productivity of the reservoir after 10 years of production was caused by condensate blockage. They found that condensate accumulation caused well productivity to decline by approximately 50%, even for this very lean gas. Boom et al. (1996) showed that even for a lean gas (e.g., less than 1% liquid dropout) a relatively high liquid saturation can build up in the near-wellbore region. Liquid saturations near the well can reach 50 to 60% under pseudosteady-state flow of gas and condensate (Cable et al. 2000; Henderson et al. 1998). Hydraulic fracturing of wells is a common practice to improve productivity of gas-condensate reservoirs. Modeling of gas-condensate wells with a hydraulic fracture requires taking into account non-Darcy flow. Gas velocity inside the fracture is three to four orders of magnitude higher than that in the matrix. Use of Darcy's law to model this flow can overestimate the productivity improvement. Therefore, it is necessary to use Forchheimer's equation to model this flow with an appropriate non-Darcy coefficient that takes into account the gas-relative permeability and water saturation.

A Holistic Study on Performance Evaluation of Horizontal Wells and its Implications on Tight Spacing Drilling Strategy in Mauddud Reservoir

2021 ◽  
Author(s):  
Lakshi Konwar ◽  
Bader Alhammadi ◽  
Ebrahim Alawainati ◽  
Ajithkumar Panicker
Keyword(s):  
Performance Evaluation ◽  
Future Development ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Water Production ◽  
Vertical Wells ◽  
Productivity Improvement ◽  
Well Productivity ◽  
Improvement Factor

Abstract The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation. Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir. Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area. Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injection using both vertical and horizontal wells.

Psychological approaches to productivity improvement.

1983 ◽  
Vol 38 (4) ◽  
pp. 468-472 ◽  
Author(s):  
Raymond A. Katzell ◽  
Richard A. Guzzo
Keyword(s):  
Productivity Improvement
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