Drawdown Guidelines for Sand Control Completions
- David L. Tiffin (BP America Inc.) | Michael H. Stein (BP America Inc.) | Xiuli Wang (BP America Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 5-8 October, Denver, Colorado
- Publication Date
- Document Type
- Conference Paper
- 2003. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 1.3.2 Subsea Wellheads, 4.2.3 Materials and Corrosion, 3.2.5 Produced Sand / Solids Management and Control, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 2.4.5 Gravel pack design & evaluation, 3.3.1 Production Logging, 4.3.3 Aspaltenes, 2.2.2 Perforating, 6.3.3 Operational Safety, 5.6.4 Drillstem/Well Testing, 2.4.6 Frac and Pack, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 3 Production and Well Operations
- 14 in the last 30 days
- 2,561 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
This paper details a method for determining maximum safe production rates for sand control wells. This method was developed from a thorough compilation of data from over 200 sand control wells. As a result of this analysis, a simple function of flux (fluid flow per unit area of screen) proved very reliable at separating wells operating safely from those resulting in damaged screens or unacceptable amounts of produced sand.
Prior to this work, BP (and the industry) used a variety of methods to attempt to optimize production from sand control wells. Most of these prior methods use pressure drop across the completion and were loosely based on experience and rules of thumb. It is shown that these pressure based draw down limits are either ineffective for managing risk of well integrity or unnecessarily constrain well productivity.
We are currently using this new flux-based approach as a basis of design for new wells and to open existing wells to a maximum safe operating production rate. Significant production addition has been added without any well failures as a result of opening up these artificially constrained wells. We furthermore anticipate preventing future well failures caused by operating at too high a rate. Earlier in 2002, two BP-operated sand control wells suffered apparent screen erosion failures; both operating at low drawdowns and safe limits using old guidelines, but at flux rates exceeding these new proposed guidelines.
Most operators limit production rates in wells with a sand control completion for fear of damaging the completion and losing the well. Operators generally control these wells by maintaining a maximum pressure drawdown (reservoir pressure or shut-in bottom hole pressure minus bottom hole flowing pressure) across the completion. Maximum recommended pressure drops ranging from 500 psi to 1000 psi are common. Experience and success of nearby wells is the usual basis for determining these pressure drawdowns.
Our first attempt at correlating data was to see how the data lined up with drawdown. This is presented in Figure 1. Note that the green wells (No problems) had a slightly higher average drawdown than those that failed (red) as well as a higher average drawdown than those wells constrained by sand production (yellow). (Data classification is discussed in more detail later.) It is clear that drawdown applied in this way does not help predict safe operating conditions; nor can it be used to optimize production rates.
Although drawdown is not a good parameter to predict whether a sand control completion will fail or not, drawdown or pressure drop across the completion is a key parameter in determining when the sand matrix "fails" and individual sand grains can be transported by the fluid flow entering a well. This may be the basis of using drawdown to control wells with a sand control completion. Many models and predictive techniques are available to make this determination based on rock strength measurements. Depletion forces also act to weaken the sand matrix resulting in a well capable of producing sand free at high drawdowns early in well life, but failing later in life with the same or smaller drawdown after the reservoir is partially depleted. Also, just because a rock "fails" does not mean sand will be produced 1-3.
Sand control completions, like frac packs and gravel packs, are designed to contain the sand whether reservoir "failure" has occurred or not. For this reason, using drawdown to control wells with effective sand control completions only makes theoretical sense when there is an ineffective or improperly installed completion in place; or in a very compressible highly depleted formation where wellbore and screen collapse is a risk. (Our data set contained only one example of a wellbore collapse and a screen crushing failure mechanism brought on by excessive depletion.)
Our analysis of screen failures indicated that screen erosion was by far the most common screen failure mechanism (other than "infant" failures), even with a good quality completion in place (complete annulus pack with an undamaged and unplugged screen). Erosion of the screen is caused by fluid flow through the screen with a small amount of fine sand particles. These solids greatly accelerate erosion of the screen.
|File Size||384 KB||Number of Pages||10|