Analysis of Pressure Data From Vertically Fractured Injection Wells

1981 ◽  
Vol 21 (01) ◽  
pp. 5-20
Author(s):  
Curtis O. Bennett ◽  
Albert C. Reynolds ◽  
Rajagopal Raghavan
Keyword(s):  
Enhanced Recovery ◽  
Outer Boundary ◽  
Fracture Plane ◽  
Pressure Data ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Type Curve ◽  
Pressure Behavior ◽  
Fracture Length ◽  
Fracture Orientation

Abstract This study investigates the flowing and shut-inpressure behavior of a fractured well located in asquare drainage region with the outer boundary at aconstant pressure. The fracture plane lies on one ofthe diagonals of the square. The report shows how toanalyze pressure data for a five-spot pattern when thefracture orientation is most favorable (from theviewpoint of sweep efficiency). Comparisons aremade with studies in the literature that assume anunfavorable fracture orientation. Fractureorientation must be considered in the analysis ofpressure data for the following conditions:smallfracture-penetration ratios,large flowing timesprior to shut-in, andlarge values of fractureflow capacity. Insights into the application of type-curve analysisto estimate drainage volumes are presented. Claimsin the literature regarding the determination of thedrainage volume by type-curve matching appear tobe unrealistic. Introduction No quantitative data are available on the effect of thecompass orientation of a vertical fracture on pressuretransient data (injection or falloff). This is surprisingsince pressure falloff tests are the principal means ofdetermining the efficacy of a fluid-injectionprogram - e.g., the effective formation flowcapacity, injectivity, skin factor, average reservoirpressure, and position of the flood front. Perhaps the dearth of information on this topic isdue to the fracture lengths being small comparedwith interwell distances in most waterflood orgas-injection projects. If the fracture length is smallcompared with the interwell distance, the orientationof the fracture should have a negligible effect on theshape of the pressure vs. time curve. However, withnew enhanced recovery projects that require closerwell spacing, interwell distances are of the same orderof magnitude as the created fracture length. In such instances, compass orientation of a vertical fracturecan have a significant effect on pressure data. All studies of the transient pressure behavior offractured wells in a bounded drainage region haveassumed that the fracture plane is parallel to theboundaries, which were considered to be eitherclosed or at constant pressure. Raghavan andHadinoto showed that the constant pressureouter-boundary solutions can be applied to a fractured wellin a five-spot injection-production pattern. However, the assumption that the fracture plane is parallel tothe boundaries of the square drainage region impliesthat the fracture is aligned directly with two of theadjacent producers. Clearly, this is only one of themany compass orientations that may exist in thefield; if consideration is given to the sweep efficiency of the flood, then this orientation would be the leastdesirable since the sweep efficiency at breakthroughwill be minimal. The most favorable fractureorientation would be the one in which the fractureplane lies along the diagonal of the square drainageregion (Fig. 1). As already mentioned, the fractureorientation may not have a significant effect ontransient data if the fracture lengths are small - butfor long fracture lengths, the effect of the orientationon the pressure behavior of injection wells can besignificant. Thus, it appears necessary to determinethe effect of fracture orientation on the pressurebehavior of fractured injection wells. SPEJ P. 5^

Analysis of Pressure Data for Fractured Wells: The Constant-Pressure Outer Boundary

1978 ◽  
Vol 18 (02) ◽  
pp. 139-150 ◽  
Author(s):  
R. Raghavan ◽  
Nico Hadinoto
Keyword(s):  
Constant Pressure ◽  
Outer Boundary ◽  
Reservoir Pressure ◽  
Pressure Gradients ◽  
Pressure Data ◽  
Pressure Behavior ◽  
Fracture Length ◽  
Infinite Conductivity ◽  
Production Pattern ◽  
Fractured Well

Abstract Analysis of flowing and shut-in pressure behavior of a fractured well in a developed live-spot fluid injection-production pattern is presented. An idealization of this situation, a fractured well located at the center of a constant pressure square, is discussed. Both infinite-conductivity and uniform-flux fracture cases are considered. Application of log-log and semilog methods to determine formation permeability, fracture length, and average reservoir pressure A discussed. Introduction The analysis of pressure data in fractured wells has recovered considerable attention because of the large number of wells bat have been hydraulically fractured or that intersect natural fractures. All these studies, however were restricted to wells producing from infinite reservoirs or to cases producing from infinite reservoirs or to cases where the fractured well is located in a closed reservoir. In some cases, these results were not compatible with production performance and reservoir characteristics when applied to fractured injection wells. The literature did not consider a fractured well located in a drainage area with a constant-pressure outer boundary. The most common example of such a system would be a fractured well in a developed injection-production pattern. We studied pressure behavior (drawdown, buildup, injectivity, and falloff) for a fractured well located in a region where the outer boundaries are maintained at a constant pressure. The results apply to a fractured well in a five-slot injectionproduction pattern and also should be applicable to a fractured well in a water drive reservoir. We found important differences from other systems previously reported. previously reported. We first examined drawdown behavior for a fractured well located at the center of a constant-pressure square. Both infinite-conductivity and uniform-flux solutions were considered. The drawdown solutions then were used to examine buildup behavior by applying the superposition concept. Average reservoir pressure as a function of fracture penetration ratio (ratio of drainage length to fracture length) and dimensionless time also was tabulated. This represented important new information because, as shown by Kumar and Ramey, determination of average reservoir pressure for the constant-pressure outer boundary system was not as simple as that for the closed case since fluid crossed the outer boundary in an unknown quantity during both drawdown (injection) and buildup (falloff). MATHEMATICAL MODEL This study employed the usual assumptions of a homogeneous, isotropic reservoir in the form of a rectangular drainage region completely filled with a slightly compressible fluid of constant viscosity. Pressure gradients were small everywhere and Pressure gradients were small everywhere and gravity effects were neglected. The outer boundary of the system was at constant pressure and was equal to the initial pressure of the system. The plane of the fracture was located symmetrically plane of the fracture was located symmetrically within the reservoir, parallel to one of the sides of the boundary (Fig. 1). The fracture extended throughout the vertical extent of the formation and fluid was produced only through the fracture at a constant rate. Both the uniform-flux and the infinite-conductivity fracture solutions were considered. P. 139

Transient Pressure Behavior for a Well With a Finite-Conductivity Vertical Fracture

1978 ◽  
Vol 18 (04) ◽  
pp. 253-264 ◽  
Author(s):  
Heber Cinco L. ◽  
F. Samaniego V. ◽  
N. Dominguez A.
Keyword(s):  
Early Time ◽  
Curve Analysis ◽  
Hydraulic Fractures ◽  
Finite Conductivity ◽  
Pressure Data ◽  
Transient Pressure ◽  
Type Curve ◽  
Fracture Characteristics ◽  
Vertical Fracture ◽  
Pressure Behavior

Abstract A mathematical model was developed to study the transient behavior of a well with a finite-conductivity vertical fracture in an infinite slab reservoir. For values of dimensionless time of interest, to >10, the dimensionless wellbore pressure, p, can be correlated by the dimensionless group; wk / x k, where w, k, and x are the width, permeability, and half length of the fracture, respectively, and k represents the formation permeability. Results when plotted as a function of P vs log to give, for large t, a 1.151-slope straight line; hence, semilogarithmic pressure analysis methods can be applied. When plotted in terms o/ log P vs log t, a family of curves of characteristic shape result. A type-curve matching procedure can be used to analyze early time transient procedure can be used to analyze early time transient pressure data to obtain the formation and fracture pressure data to obtain the formation and fracture characteristics. Introduction Hydraulic fracturing is an effective technique for increasing the productivity of damaged wells or wells producing from low permeability formations. Much research has been conducted to determine the effect of hydraulic fractures on well performance and transient pressure behavior. The results have been used to improve the design of hydraulic fractures. Many methods have been proposed to determine formation properties and fracture characteristics from transient pressure and flow rate data. These methods have been based on either analytical or numerical solutions of the transient flow of fluids toward fractured wells. Recently, Gringarten et al. made an important contribution to the analysis of transient pressure data of fractured wells. They presented a type-curve analysis and three basic presented a type-curve analysis and three basic solutions: the infinite-fracture conductivity solution (zero pressure drop along a vertical fracture the uniform flux solution for vertical fractures, and the uniform flux solution for horizontal fractures. Although the assumption of an infinite fracture conductivity is adequate for some cases, we must consider a finite conductivity for large or very low flow capacity fractures. Sawyer and Locke studied the transient pressure behavior of finite-conductivity vertical fractures in gas wells. Their solutions cannot be used to analyze transient pressure data because only specific cases were presented. In this study, we wanted to prepare general solutions for the transient pressure behavior of a well intersected by a finite-conductivity vertical fracture. The solutions sought should be useful for short-time or type-curve analysis. We also wanted to show whether conventional methods could be applied to analyze transient pressure data for these conditions. A combination of both methods, as pointed out by Gringarten to al., should permit an pointed out by Gringarten to al., should permit an extraordinary confidence level concerning the analysis of field data. STATEMENT OF THE PROBLEM AND DEVELOPMENT OF FLOW MODELS The transient pressure behavior for a fractured well can be studied by analyzing the solution of the differential equations that describe this phenomenon with proper initial and boundary conditions. To simplify the derivation of flow models, the following assumptions are made.An isotropic, homogeneous, horizontal, infinite, slab reservoir is bounded by an upper and a lower impermeable strata. The reservoir has uniform thickness, h, permeability, k, and porosity, which are independent of pressure.The reservoir contains a slightly compressible fluid of compressibility, c, and viscosity, mu, and both properties are constant.Fluid is produced through a vertically fractured well intersected by a fully penetrating, finite-conductivity fracture of half length, x, width, w, permeability, k, and porosity, phi . These fracture permeability, k, and porosity, phi . These fracture characteristics are constant. Fluid entering the wellbore comes only through the fracture. A system with these assumptions is shown in Fig. 1. In addition, we assume that gravity effects are negligible and also that laminar flow occurs in the system.

Low-Cost Measurement of Hydraulic Fracture Dimensions Using Pressure Data in Treatment and Observation Wells – A Workflow for Every Well

2021 ◽  
Author(s):  
A. Kirby Nicholson ◽  
Robert C. Bachman ◽  
R. Yvonne Scherz ◽  
Robert V. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Hydraulic Fracture ◽  
Full Scale ◽  
Pressure Data ◽  
Observation Well ◽  
High Quality ◽  
Fracture Length ◽  
Geometry Model ◽  
Observation Wells

Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.

Field Determination of Fracture Propagation Mode Using Downhole Pressure Data

2015 ◽  
Author(s):  
Ali Daneshy ◽  
Chad Touchet ◽  
Fred Hoffman ◽  
Mike McKown
Keyword(s):  
Propagation Mode ◽  
Fluid Migration ◽  
Pressure Data ◽  
Isolation System ◽  
Fracture Orientation ◽  
Coiled Tubing ◽  
Treatment Data ◽  
Set Up ◽  
Adjacent Fractures ◽  
First Time

Abstract This paper presents the analysis results of 60 single stage fracturing treatments performed in a horizontal well using cemented casing sleeves and a coiled tubing deployed frac isolation system as the completion method. In this carefully set-up and executed treatment, separation between the toe stages was 97 feet, and near the heel it was 55 feet. Pressure data was collected above and below the retrievable plug used for stage isolation. This data was used for analysis of fracturing treatment data which included mode of propagation, completion efficiency, and a rough estimate of fracture orientation. The analysis showed that; There was no interaction between adjacent fractures during five of the sixty fracturing stages. None of these was in the well interval with shorter fracture spacingFracture shadowing occurred during six fracture stages, again none in the shorter spacing intervalMinor cement defects (micro-annuli) caused some fluid migration into the passive segment of the well. This happened in 27 stages. Of these; In eleven cases the cement defects were plugged after a while, causing the migration of fracturing fluid into the passive interval to stop.In sixteen other cases the fluid migration through cement micro-annuli continued during fracturing.During ten stages, defective zone isolation and fluid migration caused a pressure increase of several hundred psi in the passive segment of the well. But this did not result in extension of passive fractures.The volume of migrated slurry due to inadequate zone isolation was mostly a very small fraction of the injected volume.During five stages poor cement quality hampered stage isolation and caused immediate link between adjacent active and passive intervals and extension of passive fractures.The data indicate possible connection between the active and one passive fracture in four stages.Shorter spacing between stages increased the incidents of fluid migration due to poor cement qualityThe fracturing pressure variations during the treatments did not indicate presence of large stress shadowingA rough estimation of fracture orientation indicates that they were likely to be vertical and nearly perpendicular to the wellbore.The fracture growth pattern can best be described as off-balance. To our knowledge, this is the first time existence of direct communication between adjacent fractures has been observed through actual pressure interference data.

Reserves Determination Using Type Curve Matching and Extended Material Balance Methods in the Medicine Hat Shallow Gas Field

1994 ◽  
Author(s):  
S. L. West ◽  
P. J. R. Cochrane
Keyword(s):  
Material Balance ◽  
Poor Quality ◽  
Curve Matching ◽  
Pressure Data ◽  
Gas Reservoirs ◽  
Shallow Gas ◽  
Gas Field ◽  
Type Curve ◽  
Balance Analysis ◽  
Diffusivity Equation

Tight shallow gas reservoirs in the Western Canada Basin present a number of unique challenges in accurately determining reserves. Traditional methods such as decline analysis and material balance are inaccurate due to the formations' low permeabilities and poor pressure data. The low permeabilities cause long transient periods not easily separable from production decline using conventional decline analysis. The result is lower confidence in selecting the appropriate decline characteristics (exponential or harmonic) which significantly impacts recovery factors and remaining reserves. Limited, poor quality pressure data and commingled production from the three producing zones results in non representative pressure data and hence inaccurate material balance analysis. This paper presents the merit of two new methods of reserve evaluation which address the problems described above for tight shallow gas in the Medicine Hat field. The first method applies type curve matching which combines the analytical pressure solutions of the diffusivity equation (transient) with the empirical decline equation. The second method is an extended material balance which incorporates the gas deliverability theory to allow the selection of appropriate p/z derivatives without relying on pressure data. Excellent results were obtained by applying these two methodologies to ten properties which gather gas from 2300 wells. The two independent techniques resulted in similar production forecasts and reserves, confirming their validity. They proved to be valuable, practical tools in overcoming the various challenges of tight shallow gas and in improving the accuracy in gas reserves determination in the Medicine Hat field.

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim Hassan ◽  
Naser Alajmi ◽  
Jimmy Nesbit ◽  
Bastien Thery ◽  
...  
Keyword(s):  
Polymer Solution ◽  
Injection Pressure ◽  
High Viscosity ◽  
Production Well ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Appreciable Change ◽  
Well Pattern ◽  
Gel Treatment ◽  
Viscosity Polymer

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.

Mechanism Analysis of Indigenous Microbial Enhancement for Residue Oil Recovery

2011 ◽  
Vol 365 ◽  
pp. 305-311
Author(s):  
Fu Chang Shu ◽  
Yue Hui She ◽  
Zheng Liang Wang ◽  
Shu Qiong Kong
Keyword(s):  
Oil Recovery ◽  
Mechanism Analysis ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
The North ◽  
Physico Chemical ◽  
Production Wells ◽  
Microbial Enhancement ◽  
Filtration Properties ◽  
Technological Treatment

Biotechnological nutrient flooding was applied to the North block of the Kongdian Oilfield during 2001-2005. The biotechnology involved the injection of a water-air mixture made up of mineral nitrogen and phosphorous salts with the intent of stimulating the growth of indigenous microorganisms. During monitoring of the physico-chemical, microbiological and production characteristics of the North block of the Kongdian bed, it was revealed significant changes took place in the ecosystem as a result of the technological treatment. The microbial oil transformation was accompanied by an accumulation of carbonates, lower fatty acids and biosurfactants in water formations, which is of value to enhanced oil recovery. The microbial metabolites changed the composition of the water formation, favored the diversion of the injected fluid from closed, high permeability zones to upswept zones and improved the sweep efficiency. The results of the studies demonstrated strong hydrodynamic links between the injection wells and production wells. Microbiological monitoring of the deep subsurface ecosystems and the filtration properties of the fluids are well modified, producing 40000 additional tons of oil in the test areas.

Analyzing Production Data From Hydraulically Fractured Wells: The Concept of Induced Permeability Field

2014 ◽  
Vol 17 (02) ◽  
pp. 220-232 ◽  
Author(s):  
Gorgonio Fuentes-Cruz ◽  
Eduardo Gildin ◽  
Peter P. Valkó
Keyword(s):  
Hydraulic Fracturing ◽  
Outer Boundary ◽  
Production Performance ◽  
Fracture Plane ◽  
Late Time ◽  
Linear Flow ◽  
Type Curves ◽  
Stimulated Reservoir Volume ◽  
New Model ◽  
Permeability Field

Summary This work introduces a new model for the production-decline analysis (PDA) of hydraulically fractured wells on the basis of the concept of the induced permeability field. We consider the case when the hydraulic-fracturing operation—in addition to establishing the fundamental linear-flow geometry in the drainage volume—alters the ability of the formation to conduct fluids throughout, but with varying degrees depending on the distance from the main fracture plane. We show that, under these circumstances, the reservoir response departs from the uniform-permeability approach significantly. The new model differs from the once promising group of models that are inherently related to power-law-type variation of the permeability-area product and thus are burdened by a mathematical singularity inside the fracture. The analysis of field cases reveals that the induced permeability field can be properly represented by a linear or exponential function characterized by the maximal induced permeability k0 and the threshold permeability k*. Both these permeabilities are induced (superimposed on the formation) by the hydraulic-fracturing treatment; thus, the model can be considered as a simple, but nontrivial, formalization of the intuitive stimulated-reservoir-volume (SRV) concept. It is quite reasonable to assume that the maximum happens at the fracture face and that the minimum happens at the outer boundary of the SRV. The contrast between maximal and minimal permeability, SR = k0/k*, will be of considerable interest, and thus, we introduce a new term for it: stimulation ratio (SR). Knowledge of these parameters is crucial in evaluating the effectiveness of today's intensively stimulated well completions, especially multifractured horizontal wells in shale gas. The approach describes, in a straightforward manner, the production performance of such wells exhibiting transient linear flow and late-time boundary-dominated flow affected also by a skin effect (i.e., by an additional pressure drop in the system characterized by linear dependence on production rate). This work provides the induced-permeability-field model within the single-medium concept, and shows that some features widely believed to require a dual-medium (double-porosity) representation are already present. Advantages and drawbacks related to applying the concept in a dual-medium approach will be discussed in an upcoming work. We present the model and its analytical solution in Laplace space. We provide type curves for decline-curve analysis, closed-form approximate solutions in the time domain, field examples, and practical guidelines for the analysis of commonly occurring production characteristics of massively stimulated reservoirs.

Water Injection Profile Modification in a Layered Reservoir With Polymer Treatment

2000 ◽  
Vol 3 (03) ◽  
pp. 197-203 ◽  
Author(s):  
S.M. El-Hadidi ◽  
G.K. Falade ◽  
C. Dabbouk ◽  
F. Al-Ansari
Keyword(s):  
Water Intake ◽  
Water Injection ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Profile Modification ◽  
Water Breakthrough ◽  
Pattern Size ◽  
Infill Drilling ◽  
Remedial Actions

Summary The main focus of this paper is the applications of polymer treatment in controlling injectivity and the improvement of the near-wellbore injection profiles. Reservoir high-permeability zones causing distortions of water injection profiles at the wellbore, and the possible existence of layer barriers, were identified with conventional investigation tools such as openhole logs, production logging tools, formation, and microscanners. A polymer screening procedure was put in place so that appropriate polymer formulations that can reduce fluid mobility in the high-permeability zones at the near-wellbore region can be identified. The use of these polymer formulations facilitated the improvement of wellbore injectivity profiles. The field performance of the polymer treatment program was ascertained by the use of a monitoring program that combined the application of the production logging tools and well-test analyses. Introduction The presence of high-permeability streaks and fractures are common occurrences in stratified carbonate reservoirs. If these reservoirs are subjected to patterned waterflooding operations, it is likely that the highly permeable zones will accept most, if not all, of the water injected. This tends to distort the injectivity profile at the wellbore, and raises the possibility of an eventual poor reservoir coverage and sweep efficiency. Therefore, a successful waterflood project necessarily demands a clear understanding of reservoir characteristics with a view to identify occurrences of high-permeability streaks, channels, and layer barriers, so that adequate remedial actions that can reduce the adverse effects of these reservoir characteristics on waterflood performance can be put in place. One type of remedial actions that has recently gained prominence is the use of polymer1–3 and nonpolymer4,5 agents for injection/production wellbore profile modification for vertical wells. A case history for horizontal well application of polymer treatment was recently documented in the petroleum literature.6 This paper presents the screening and evaluation procedures for the selection of a crosslinked polymer formulation for use in profile modification in water injection wells. The post-polymer injection monitoring of the polymer-treated injection wells and the surrounding producers also are presented. Background History The reservoir under consideration is a mature reservoir under five-spot pattern water injection. The injection pattern size has been under continual modification by implementing a carefully planned program of infill drilling and the conversion of some original producers to injectors. This progressive review of pattern size has reduced the distance of producers to injectors from an original value of 2.8 km to a current value of about 1.4 km. Simulation studies indicated that water production from this reservoir is not expected to start before 2010. However, it has been observed that some of the producers have started experiencing premature water breakthrough. Analysis of produced water confirmed that water being produced by these wells comes largely from injected seawater. Field-wide investigation as to the cause(s) of premature water breakthrough in some wells was initiated. These investigations involved a complete re-evaluation of all available open- and cased-hole logs of all producers and the neighboring injectors within and around the pattern in which premature water breakthrough has been observed. Special considerations were given to production logging tool (PLT) logs, particularly newly acquired PLT, pulse neutron logs, and core data from infill drilling and dynamic testing programs such as MDT, RFT, and transient well tests. This data acquisition program was designed to correlate injection profiles of the various water injection wells in the reservoir. The investigation confirmed that the earlier static geological model that splits the reservoir into six layers (A, B, C, D, E, and F), separated by five stylolitic intervals (S1, S2, S3, S4, and S5, respectively, as shown in Fig. 1) may require further refinements. Furthermore, observations from core and RFT data showed Layers A and B to be characterized by zones of high-permeability streaks. Evaluation of water-cut profiles throughout the entire reservoir did not seem to support any directional fluid drift caused by reservoir-wide directional permeability. PLT results did, however, confirm that most of the water injected into most of the injectors do preferentially and disproportionately go into the top reservoir Layers A and B. The lower reservoir Layers C, D, E and F show no evidence of any quantifiable injection water intake. PLT surveys of the producers also show that Layers A and B might have accounted for all the water production at the producers. This could suggest that the high-permeability streaks are controlling the waterflood flow path inside the reservoir. In most practical cases of waterflood, the ideal piston-like displacement by water could hardly be achieved. This is more so for cases where high-permeability streaks, thief zones, or high-conductivity fractures cause a disproportionate amount of recoverable oil reserves that can be bypassed, resulting in poor volumetric sweep efficiency. In order to optimize the water injection program by reducing the incidence of premature water breakthrough, vertical conformance of water intake profiles at the injectors must be improved. Therefore, a reduction in the water injection into the upper high-permeability Layers A and B of this reservoir while increasing intake into the less-permeable lower Layers C, D, E, and F could improve the water injection performance of the reservoir substantially. In view of the above, it was decided to implement a polymer treatment program on some selected injectors, particularly the original high-capacity injectors where premature water breakthrough has been observed within its flood pattern. In doing this, it is hoped that injected polymer will infiltrate the high-permeability streaks in Layers A and B and reduce the injectivities of these layers by selective permeability reduction. If subsequent injection wellhead pressure remains the same, it is expected that the water intake into Layers C, D, E, and F will proportionately increase.

Sign in / Sign up

Export Citation Format

Share Document