Meridian Operating — Portfolio Diagnostic

Well	Dev ID	Early SP (psi)	Late SP (psi)	Creep	Current class	Latest MCF/D
Markham Heirs #1 Alloc	19820	50	345	+590%	DECLINING	0
Markham Heirs #2 Alloc	19827	54	344	+537%	DECLINING	0
Stanhope #1 Alloc	19868	59	557	+844%	LOW_FT	71
Kirby #1 Alloc	19870	73	408	+459%	LOW_FT	250
Kirby #3 Alloc	19872	49	397	+710%	LOW_FT	21
Stanhope #3 Alloc	19873	57	403	+607%	DECLINING	80
Stanhope #4 Alloc	19875	72	442	+514%	STABLE	18
Stanhope #5 Alloc	19876	61	433	+610%	STABLE	124
Ashcroft #4 Alloc	19879	58	435	+650%	DECLINING	278
Westbrook #1 Alloc	19882	61	377	+518%	DECLINING	170

Well	Dev	Battery	Driver
Lyman 3	40765	8.239976 V	NX_Floboss
Roundtable Discharge	44761	11.489601 V	NX_Totalflow

Well	Dev	Age	Likely cause
Baxter #1 Alloc	19852	12d	telecom
HARTSFIELD #1	38873	4d	polling
CLEMENT 006	38884	6d	polling
Wolford 2-4-5 CK	17487	7d	telecom
Halsey Sales Chk	19846	10d	telecom

Well	Dev	Driver	Likely cause
BRADFORD ECHO 006H	46027	NX_Totalflow	telecom_dead
Gallatin-West Sales Chk	6138	NX_Totalflow	telecom_dead
Lamar #1H	26525	NX_Totalflow	telecom_dead
WESLEY 002	46031	NX_Totalflow	telecom_dead
TREVINO G A 010	46015	NX_Totalflow	unknown
TREVINO G A 05 10 SALES CHK	46016	NX_Totalflow	unknown
SALADO CREEK 010	38845	NX_Totalflow	unknown

Well	Signal	Recommended	$/mo	MCF/D
Bayou South Sales Chk (Kirby CP Mid)	temp min 52F / avg 67F (cloud-point risk), 30d 404 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	20
VINTON 005H	temp min 50F / avg 75F (cloud-point risk), 30d 296 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	14
BRIGHTON 013 Gas Lift	temp min 44F / avg 68F (cloud-point risk), 30d 170 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	8
Henry R Shaw #2 Alloc	temp min 51F / avg 73F (cloud-point risk), 30d 140 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	7
Roundtable Discharge	temp min 52F / avg 76F (cloud-point risk), 30d 121 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	6
Kincaid Marsh C/M	temp min 48F / avg 75F (cloud-point risk), 30d 123 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	6
Rockwell Meadows GU #7	temp min 55F / avg 69F (cloud-point risk), 30d 105 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	5
TREVINO G A 07 08 11 & FAIRMONT SALES CHK	temp min 54F / avg 66F (cloud-point risk), 30d 90 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	4
Stanhope #5 Alloc	temp min 54F / avg 72F (cloud-point risk), 30d 82 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	4
Kirby #1 Alloc	temp min 54F / avg 71F (cloud-point risk), 30d 84 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	4
HARMON-PIERCE DONALDSON	temp min 46F / avg 65F (cloud-point risk), 30d 54 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	3
Markham Heirs #2 Alloc	temp min 55F / avg 71F (cloud-point risk), 30d 43 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	3
Mabry 2H	temp min 54F / avg 67F (cloud-point risk), 30d 47 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	3
ORION 001	temp min 53F / avg 68F (cloud-point risk), 30d 38 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	3
Roundtable CP Check	temp min 53F / avg 68F (cloud-point risk), 30d 55 MCF/D	Hot-oil + paraffin solvent batch (initial), then continuous paraffin inhibitor at 10-20 ppm	350	3

Well	Signal	Recommended	$/mo	MCF/D
Holloway #1	LOADING class, 30d 68 MCF/D, DP rising, rate falling — classic foamer candidate	FSC 600 (or equivalent) surfactant foamer, 1 qt/day injected downhole OR daily soap sticks pending capillary string install	450	10
Ramsey Fields 2H Gas Lift	LOADING class, 30d 355 MCF/D, DP rising, rate falling — classic foamer candidate	FSC 600 (or equivalent) surfactant foamer, 1 qt/day injected downhole OR daily soap sticks pending capillary string install	450	53
Bayou So Comp Disch	LOADING class, 30d 609 MCF/D, DP rising, rate falling — classic foamer candidate	FSC 600 (or equivalent) surfactant foamer, 1 qt/day injected downhole OR daily soap sticks pending capillary string install	450	91
Bayou South Sales Chk (Kirby CP Mid)	LOADING class, 30d 404 MCF/D, DP rising, rate falling — classic foamer candidate	FSC 600 (or equivalent) surfactant foamer, 1 qt/day injected downhole OR daily soap sticks pending capillary string install	450	60

Well	Signal	Recommended	$/mo	MCF/D
Bancroft #2H Alloc	12 days of small back-flow (avg 0.01 MCF) — meter chatter from liquid slugs / scale bridging	Water sample for iron/Ba/Sr scale panel. If CaCO3/BaSO4 positive, continuous scale inhibitor 10-20 ppm + periodic acid batch	300	8
BRIGHTON 010	24 days of small back-flow (avg 0.01 MCF) — meter chatter from liquid slugs / scale bridging	Water sample for iron/Ba/Sr scale panel. If CaCO3/BaSO4 positive, continuous scale inhibitor 10-20 ppm + periodic acid batch	300	2
Oakridge Paxton Sales Check Meter	7 days of small back-flow (avg 0.01 MCF) — meter chatter from liquid slugs / scale bridging	Water sample for iron/Ba/Sr scale panel. If CaCO3/BaSO4 positive, continuous scale inhibitor 10-20 ppm + periodic acid batch	300	3

Well	Signal	Install $	MCF/D	Payback mo
WEATHERSBY 1H	FT 51%, slug ratio 24x, 7d 197 MCF/D — strong plunger signature	$8-12k	58	2
Henry R Shaw #2 Alloc	FT 29%, slug ratio 44x, 7d 166 MCF/D — strong plunger signature	$8-12k	49	2
Lamar #1H	FT 30%, slug ratio 14x, 7d 164 MCF/D — strong plunger signature	$8-12k	49	2
Kincaid Marsh C/M	FT 35%, slug ratio 45x, 7d 112 MCF/D — strong plunger signature	$8-12k	33	4
Wolford 2-4-5 CK	FT 68%, slug ratio 17x, 7d 96 MCF/D — strong plunger signature	$8-12k	28	4
STANFORD 001	FT 48%, slug ratio 49x, 7d 94 MCF/D — strong plunger signature	$8-12k	28	4
Stanford MM	FT 48%, slug ratio 49x, 7d 94 MCF/D — strong plunger signature	$8-12k	28	4
Ramsey Fields Sales Check	FT 59%, slug ratio 47x, 7d 87 MCF/D — strong plunger signature	$8-12k	26	4
Westbrook #1 Alloc	FT 73%, slug ratio 22x, 7d 81 MCF/D — strong plunger signature	$8-12k	24	5
Stanhope #4 Alloc	FT 73%, slug ratio 48x, 7d 73 MCF/D — strong plunger signature	$8-12k	21	5
Kirby #1 Alloc	FT 60%, slug ratio 81x, 7d 72 MCF/D — strong plunger signature	$8-12k	21	5
BRENNER S R 1&2 CM	FT 65%, slug ratio 26x, 7d 72 MCF/D — strong plunger signature	$8-12k	21	5
Westport Center	FT 43%, slug ratio 12x, 7d 61 MCF/D — strong plunger signature	$8-12k	18	6
Dewsbury 1	FT 28%, slug ratio 11x, 7d 55 MCF/D — strong plunger signature	$8-12k	16	7
HARMON-PIERCE GREGGTON SALES CHK	FT 51%, slug ratio 14x, 7d 49 MCF/D — strong plunger signature	$8-12k	14	8

Well	Signal
Lyman Sales Chk	FT 96% (high), steady decline -28% — reservoir making water faster than current tubing can lift. Velocity string (reducing tubing ID) raises gas velocity.
Ridgewood South 1H	FT 98% (high), steady decline -17% — reservoir making water faster than current tubing can lift. Velocity string (reducing tubing ID) raises gas velocity.
Amelia Kirk Sales Check	FT 97% (high), steady decline -19% — reservoir making water faster than current tubing can lift. Velocity string (reducing tubing ID) raises gas velocity.
Cypress Landing Sales	FT 95% (high), steady decline -22% — reservoir making water faster than current tubing can lift. Velocity string (reducing tubing ID) raises gas velocity.
Lockhart #1 Alloc	FT 92% (high), steady decline -16% — reservoir making water faster than current tubing can lift. Velocity string (reducing tubing ID) raises gas velocity.

Well	Why decommission
BEAUFORT GU 3H	30d flow 0.0 MCF/D, 7d 0.0, zero-flow days 30 — economics essentially dead. Confirm P&A or return-to-service decision.
Echo Bradford 2-1H	30d flow 0.0 MCF/D, 7d 0.0, zero-flow days 30 — economics essentially dead. Confirm P&A or return-to-service decision.
HARMON PIERCE GU 001	30d flow 0.0 MCF/D, 7d 0.0, zero-flow days 30 — economics essentially dead. Confirm P&A or return-to-service decision.
Ramsey Fields Buy Back	30d flow 0.8 MCF/D, 7d 0.0, zero-flow days 28 — economics essentially dead. Confirm P&A or return-to-service decision.
Amelia Kirk #2H	30d flow 0.6 MCF/D, 7d 0.0, zero-flow days 23 — economics essentially dead. Confirm P&A or return-to-service decision.
Ashcroft #1 Alloc	30d flow 0.6 MCF/D, 7d 0.0, zero-flow days 25 — economics essentially dead. Confirm P&A or return-to-service decision.

#	Action & wells	Cost	Expected gain	Revenue	Payback	Conf
1	Gathering/compression triage on Stanhope/Ashcroft CTB cluster Markham Heirs #1 Alloc (19820), Markham Heirs #2 Alloc (19827), Stanhope #1 Alloc (19868) + 7 more	$0 (diagnosis) + $1-5k fix if comp issue, $10-25k if line restriction	+120-210 MCF/D restoration	$17,000/mo	<1 week after fix	high
2	I&E truck roll on 4 stale-mid-window RTUs (known recent production) BRADFORD ECHO 006H, Gallatin-West Sales Chk, Lamar #1H + 1 more	~$1.2k labor + parts if modem swap ($600 ea)	Restores ~120-210 MCF/D of visibility (live wells currently dark)	—	N/A (diagnostic ability)	high
3	Hot-oil + continuous paraffin inhibitor on top-5 temp-low producers Bayou South Sales Chk (Kirby CP Mid), VINTON 005H, BRIGHTON 013 Gas Lift + 2 more	~$15k initial + $2k/mo continuous	+55 MCF/D	$5,775.0/mo	1-3 months	medium
4	Holloway #1 — soap-stick daily + plunger evaluation Holloway #1	$450/mo soap, $10k if plunger	+15-30 MCF/D if recovery possible	$2,100/mo	1-4 months	medium
5	Plunger install on top-3 non-cluster candidates WEATHERSBY 1H, Henry R Shaw #2 Alloc, Lamar #1H	~$30k capital + $450/mo service	+156 MCF/D	$16,380/mo	3-6 months	medium
6	Ramsey Fields group (1, 2H GL, 3H, Sales Check) — gathering line pressure investigation + workover eval on 3H/Sales Ramsey Fields Sales Check, Ramsey Fields 3H, Ramsey Fields 2H Gas Lift + 1 more	$0 investigation + $30-60k if workover	+80-150 MCF/D if restoration possible	$10,500/mo	2-6 months	medium
7	Lyman 3 + Roundtable Discharge — emergency battery swap Lyman 3, Roundtable Discharge	$800 total (AGM 100Ah x2 + labor)	Prevent loss of RTU visibility	—	N/A (infrastructure)	high
8	Stale RTU recovery — 5 devices 4-14d dark Baxter #1 Alloc, HARTSFIELD #1 , CLEMENT 006 + 2 more	$1.5k truck rolls	Prevent rollover to OFFLINE class, restore polling	—	N/A	high
9	Patch WellRX classifier: SALADO CREEK 011 and ORION 001 are gas-lift buyback meters, not ZERO_FLOW failures SALADO CREEK 011, ORION 001	Software change	Remove false alarms, cleaner daily reports	—	Immediate	high
10	30-day pumper ground-truth sweep on 54 no-data OFFLINE devices (distinguish decommissioned from dark) (all 44 no-rows OFFLINE devices)	~$8-15k (10 sites/day, 30-day sweep)	Clean fleet count, identify 5-10 real live-but-dark wells for follow-up	$4,200/mo	2-3 months	medium

CASE · 001 · DEV 39773 DECLINING · RED

Ramsey Fields Sales Check

DECLINING · target recovery +104 MCF/D · $10,920/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 87 vs 30d 295 MCF/D (-70%, ~-208 MCF/D lost)
DP delta -88%
Flow time 59%
Zero-flow days in window: 7

Primary diagnosis

Moderate decline (-70%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+62-124 MCF/D if mechanical	1-2 weeks

CASE · 002 · DEV 19856 DECLINING · RED

Bancroft #2H Alloc

DECLINING · target recovery +97 MCF/D · $10,185/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 106 vs 30d 300 MCF/D (-65%, ~-194 MCF/D lost)
DP delta -40%
Flow time 86%
Zero-flow days in window: 1

Primary diagnosis

Moderate decline (-65%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+58-116 MCF/D if mechanical	1-2 weeks

CASE · 003 · DEV 19858 DECLINING · AMBER

Bancroft Sales Chk

DECLINING · target recovery +85 MCF/D · $8,925/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 207 vs 30d 378 MCF/D (-45%, ~-170 MCF/D lost)
DP delta -35%
Flow time 99%

Primary diagnosis

Moderate decline (-45%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+51-102 MCF/D if mechanical	1-2 weeks

CASE · 004 · DEV 19874 LOADING · RED

Bayou So Comp Disch

LOADING · target recovery +82 MCF/D · $8,610/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d MCF 483 vs 30d 609 (-21%)
DP 30d avg 34.7" H2O, delta +11%
Flow time 77% (slug/intermittent)
MaxDP 30d 318" (pressure spikes indicate head-gas/slugging)
Temp min 56F (paraffin cloud-point risk on east-TX black oil)
Battery 13.7V

Primary diagnosis

Classic liquid loading signature — FT sub-80, high MaxDP spikes, DP trending up while rate drops. Flowing temp below 60F in places is suspicious for paraffin onset — include solvent batch in any hot-oil treatment.

Differential

Liquid loading below Turner/Crenshaw critical velocity
Compressor suction loss on upstream unit (check comp runtime)
Choke plugging at sales meter — verify with independent pressure upstream

Immediate action

Pumper: (1) confirm FWHP at wellhead and compare to tubing head pressure at comp station, (2) soap 1 stick/AM for 7d, (3) photo wellhead gauges and record casing-to-tubing differential, (4) if well is on Stanhope/Ashcroft CTB, coordinate with gathering operator to confirm line pressure.

Diagnostics needed

FWHP at wellhead gauge (independent of SCADA SP)
Casing pressure shut-in test — Crenshaw critical velocity
Gas analysis (CO2, H2S, water) if not current
Coordinate downstream line pressure read from gathering operator

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick trial, 1 stick/day × 7 days	~$105/wk (sticks $15 ea)	+32-57 MCF/D if liquid-loading is real	<1 week at current prices
Plunger install if soap succeeds but intermittent persists	$8-12k capital + $150/mo service	+49-82 MCF/D steady-state	3-6 months
If CTB cluster event suspected, FIX GATHERING FIRST — soap/plunger wastes money if SP is elevated	$0	preserves chemistry budget	immediate

CASE · 005 · DEV 38856 DECLINING · RED

Ramsey Fields 3H

DECLINING · target recovery +78 MCF/D · $8,190/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 0 vs 30d 157 MCF/D (-100%, ~-157 MCF/D lost)
DP delta -95%
Flow time 45%
Zero-flow days in window: 13

Primary diagnosis

Well has 13+ days of zero flow and -100% MCF loss. Either shut-in, choke-plugged, RTU value stuck, or terminal load-up with head-gas stalling lift. Need eyes on-site before any action.

Differential

Shut-in (planned or tripped safety valve)
Choke/needle valve plugged with paraffin or scale
Loaded column of water + gas — needs unload cycle
Meter/orifice plate fouled (compare with chart meter if available)

Immediate action

Pumper visit today: check wellhead gauges, cycle the choke, unload any obvious liquid column, verify FWHP and casing pressure. If casing > tubing by >200 psi, loaded column is confirmed.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+47-94 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+78-125 MCF/D	3-6 months

CASE · 006 · DEV 19867 LOW_FT · AMBER

Henry R Shaw #2 Alloc

LOW_FT · target recovery +66 MCF/D · $6,930/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 29% — well is flowing <29% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 44x — pressure surging
7d 166 MCF vs 30d 140 MCF
DP delta -6%
Temp min 51F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 29%, slug ratio 44x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+52-85 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 007 · DEV 38895 LOW_FT · AMBER

WEATHERSBY 1H

LOW_FT · target recovery +59 MCF/D · $6,195/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 51% — well is flowing <51% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 24x — pressure surging
7d 197 MCF vs 30d 202 MCF
DP delta -3%

Primary diagnosis

Classic plunger-candidate signature: FT 51%, slug ratio 24x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+47-76 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 008 · DEV 105460 DECLINING · YELLOW

Cypress Landing Sales

DECLINING · target recovery +53 MCF/D · $5,565/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 378 vs 30d 485 MCF/D (-22%, ~-107 MCF/D lost)
DP delta -16%
Flow time 95%
Temp min 50F — flag paraffin risk

Primary diagnosis

Moderate decline (-22%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+31-63 MCF/D if mechanical	1-2 weeks
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+21-42 MCF/D if paraffin-restricted	1-3 months

CASE · 009 · DEV 4566 LOW_FT · AMBER

Kincaid Marsh C/M

LOW_FT · target recovery +45 MCF/D · $4,725/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 35% — well is flowing <35% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 45x — pressure surging
7d 112 MCF vs 30d 123 MCF
DP delta -30%
Temp min 48F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 35%, slug ratio 45x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+36-58 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 010 · DEV 19879 DECLINING · AMBER

Ashcroft #4 Alloc

DECLINING · target recovery +41 MCF/D · $4,305/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 116 vs 30d 184 MCF/D (-37%, ~-68 MCF/D lost)
DP delta -62%
Flow time 85%
Zero-flow days in window: 2
SP creep 68→435 psi (+538%) — gathering backpressure event

Primary diagnosis

Stanhope/Ashcroft CTB cluster well. Static pressure trebled after April 14-17 across the entire network. This is a SYSTEM failure (compression/gathering), not 10 well failures. Individual well-level workups are the wrong first move.

Differential

Downstream compressor station offline or suction-choked
Sales line restriction/pigging issue
Plant reject / gas-quality shutdown rippling upstream

Immediate action

STOP well-level spend on this well. (1) Get comp-station SCADA pulled for the Kirby/Bayou compressor, (2) call midstream operator for line pressure history, (3) do not soap or plunge until gathering is restored — any chemistry burns before compression recovers is wasted.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Treat as gathering-system event, not well-level — see gathering_and_compression narrative	pending midstream	restoration of full 30d rate if gathering fixed	N/A (infrastructure)

CASE · 011 · DEV 49601 LOADING · RED

Holloway #1

LOADING · target recovery +36 MCF/D · $3,780/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d MCF 12 vs 30d 68 (-82%)
DP 30d avg 5.6" H2O, delta +37%
Flow time 45% (slug/intermittent)
MaxDP 30d 108" (pressure spikes indicate head-gas/slugging)
Temp min 58F (paraffin cloud-point risk on east-TX black oil)
Battery 12.6V

Primary diagnosis

Classic liquid loading signature — FT sub-80, high MaxDP spikes, DP trending up while rate drops. Flowing temp below 60F in places is suspicious for paraffin onset — include solvent batch in any hot-oil treatment.

Differential

Liquid loading below Turner/Crenshaw critical velocity
Compressor suction loss on upstream unit (check comp runtime)
Choke plugging at sales meter — verify with independent pressure upstream

Immediate action

Pumper: (1) confirm FWHP at wellhead and compare to tubing head pressure at comp station, (2) soap 1 stick/AM for 7d, (3) photo wellhead gauges and record casing-to-tubing differential, (4) if well is on Stanhope/Ashcroft CTB, coordinate with gathering operator to confirm line pressure.

Diagnostics needed

FWHP at wellhead gauge (independent of SCADA SP)
Casing pressure shut-in test — Crenshaw critical velocity
Gas analysis (CO2, H2S, water) if not current
Coordinate downstream line pressure read from gathering operator

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick trial, 1 stick/day × 7 days	~$105/wk (sticks $15 ea)	+14-25 MCF/D if liquid-loading is real	<1 week at current prices
Plunger install if soap succeeds but intermittent persists	$8-12k capital + $150/mo service	+21-36 MCF/D steady-state	3-6 months
If CTB cluster event suspected, FIX GATHERING FIRST — soap/plunger wastes money if SP is elevated	$0	preserves chemistry budget	immediate

CASE · 012 · DEV 19883 LOADING · AMBER

Bayou South Sales Chk (Kirby CP Mid)

LOADING · target recovery +34 MCF/D · $3,570/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d MCF 352 vs 30d 404 (-13%)
DP 30d avg 31.7" H2O, delta +16%
Flow time 77% (slug/intermittent)
MaxDP 30d 346" (pressure spikes indicate head-gas/slugging)
Temp min 52F (paraffin cloud-point risk on east-TX black oil)
Battery 13.2V

Primary diagnosis

Classic liquid loading signature — FT sub-80, high MaxDP spikes, DP trending up while rate drops. Flowing temp below 60F in places is suspicious for paraffin onset — include solvent batch in any hot-oil treatment.

Differential

Liquid loading below Turner/Crenshaw critical velocity
Compressor suction loss on upstream unit (check comp runtime)
Choke plugging at sales meter — verify with independent pressure upstream

Immediate action

Pumper: (1) confirm FWHP at wellhead and compare to tubing head pressure at comp station, (2) soap 1 stick/AM for 7d, (3) photo wellhead gauges and record casing-to-tubing differential, (4) if well is on Stanhope/Ashcroft CTB, coordinate with gathering operator to confirm line pressure.

Diagnostics needed

FWHP at wellhead gauge (independent of SCADA SP)
Casing pressure shut-in test — Crenshaw critical velocity
Gas analysis (CO2, H2S, water) if not current
Coordinate downstream line pressure read from gathering operator

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick trial, 1 stick/day × 7 days	~$105/wk (sticks $15 ea)	+13-23 MCF/D if liquid-loading is real	<1 week at current prices
Plunger install if soap succeeds but intermittent persists	$8-12k capital + $150/mo service	+20-34 MCF/D steady-state	3-6 months
If CTB cluster event suspected, FIX GATHERING FIRST — soap/plunger wastes money if SP is elevated	$0	preserves chemistry budget	immediate

CASE · 013 · DEV 42410 LOW_FT · AMBER

STANFORD 001

LOW_FT · target recovery +28 MCF/D · $2,940/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 48% — well is flowing <48% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 49x — pressure surging
7d 94 MCF vs 30d 78 MCF
DP delta -78%
Temp min 56F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 48%, slug ratio 49x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+22-36 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 014 · DEV 41966 LOW_FT · AMBER

Stanford MM

LOW_FT · target recovery +28 MCF/D · $2,940/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 48% — well is flowing <48% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 49x — pressure surging
7d 94 MCF vs 30d 78 MCF
DP delta -78%
Temp min 56F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 48%, slug ratio 49x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+22-36 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 015 · DEV 19821 DECLINING · RED

Roundtable CP Check

DECLINING · target recovery +27 MCF/D · $2,835/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 0 vs 30d 55 MCF/D (-100%, ~-55 MCF/D lost)
DP delta -100%
Flow time 46%
Zero-flow days in window: 7
Temp min 53F — flag paraffin risk

Primary diagnosis

Moderate decline (-100%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+16-32 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+27-43 MCF/D	3-6 months
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+10-21 MCF/D if paraffin-restricted	1-3 months

CASE · 016 · DEV 19827 DECLINING · RED

Markham Heirs #2 Alloc

DECLINING · target recovery +25 MCF/D · $2,625/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 2 vs 30d 43 MCF/D (-96%, ~-41 MCF/D lost)
DP delta -97%
Flow time 21%
Zero-flow days in window: 6
Temp min 55F — flag paraffin risk
SP creep 54→344 psi (+543%) — gathering backpressure event

Primary diagnosis

Stanhope/Ashcroft CTB cluster well. Static pressure trebled after April 14-17 across the entire network. This is a SYSTEM failure (compression/gathering), not 10 well failures. Individual well-level workups are the wrong first move.

Differential

Downstream compressor station offline or suction-choked
Sales line restriction/pigging issue
Plant reject / gas-quality shutdown rippling upstream

Immediate action

STOP well-level spend on this well. (1) Get comp-station SCADA pulled for the Kirby/Bayou compressor, (2) call midstream operator for line pressure history, (3) do not soap or plunge until gathering is restored — any chemistry burns before compression recovers is wasted.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Treat as gathering-system event, not well-level — see gathering_and_compression narrative	pending midstream	restoration of full 30d rate if gathering fixed	N/A (infrastructure)

CASE · 017 · DEV 38906 LOW_FT · AMBER

SALADO CREEK 027

LOW_FT · target recovery +23 MCF/D · $2,415/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 26% — well is flowing <26% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 0x — pressure surging
7d 56 MCF vs 30d 57 MCF
DP delta -8%

Primary diagnosis

Classic plunger-candidate signature: FT 26%, slug ratio 0x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+18-29 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 018 · DEV 19870 LOW_FT · AMBER

Kirby #1 Alloc

LOW_FT · target recovery +22 MCF/D · $2,310/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 60% — well is flowing <59% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 81x — pressure surging
7d 72 MCF vs 30d 84 MCF
DP delta -34%
Temp min 54F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 60%, slug ratio 81x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift. NOTE: well is on Stanhope/Ashcroft CTB — confirm gathering is clean before plunger capex.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+17-28 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 019 · DEV 13721 LOW_FT · AMBER

Dewsbury 1

LOW_FT · target recovery +22 MCF/D · $2,310/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 28% — well is flowing <27% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 11x — pressure surging
7d 55 MCF vs 30d 41 MCF
DP delta +53%

Primary diagnosis

Classic plunger-candidate signature: FT 28%, slug ratio 11x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+17-28 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 020 · DEV 45998 DECLINING · YELLOW

Amelia Kirk Sales Check

DECLINING · target recovery +20 MCF/D · $2,100/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 165 vs 30d 204 MCF/D (-19%, ~-39 MCF/D lost)
DP delta -36%
Flow time 97%

Primary diagnosis

Moderate decline (-19%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+11-23 MCF/D if mechanical	1-2 weeks

CASE · 021 · DEV 41774 DECLINING · RED

Mabry 2H

DECLINING · target recovery +18 MCF/D · $1,890/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 11 vs 30d 47 MCF/D (-77%, ~-36 MCF/D lost)
DP delta -91%
Flow time 40%
Zero-flow days in window: 7
Temp min 54F — flag paraffin risk

Primary diagnosis

Moderate decline (-77%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+10-21 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+18-28 MCF/D	3-6 months
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+7-14 MCF/D if paraffin-restricted	1-3 months

CASE · 022 · DEV 45609 LOW_FT · AMBER

Westport Center

LOW_FT · target recovery +18 MCF/D · $1,890/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 43% — well is flowing <43% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 12x — pressure surging
7d 61 MCF vs 30d 64 MCF
DP delta -6%
Temp min 56F — possible paraffin

Primary diagnosis

Classic plunger-candidate signature: FT 43%, slug ratio 12x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+14-23 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 023 · DEV 38897 DECLINING · RED

STANFORD 004

DECLINING · target recovery +16 MCF/D · $1,680/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 0 vs 30d 32 MCF/D (-100%, ~-32 MCF/D lost)
DP delta -100%
Flow time 22%
Zero-flow days in window: 19
Temp min 0F — flag paraffin risk

Primary diagnosis

Well has 19+ days of zero flow and -100% MCF loss. Either shut-in, choke-plugged, RTU value stuck, or terminal load-up with head-gas stalling lift. Need eyes on-site before any action.

Differential

Shut-in (planned or tripped safety valve)
Choke/needle valve plugged with paraffin or scale
Loaded column of water + gas — needs unload cycle
Meter/orifice plate fouled (compare with chart meter if available)

Immediate action

Pumper visit today: check wellhead gauges, cycle the choke, unload any obvious liquid column, verify FWHP and casing pressure. If casing > tubing by >200 psi, loaded column is confirmed.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+9-18 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+15-25 MCF/D	3-6 months
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+6-12 MCF/D if paraffin-restricted	1-3 months

CASE · 024 · DEV 19820 DECLINING · RED

Markham Heirs #1 Alloc

DECLINING · target recovery +16 MCF/D · $1,680/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 20 vs 30d 47 MCF/D (-57%, ~-27 MCF/D lost)
DP delta -84%
Flow time 12%
Zero-flow days in window: 3
SP creep 50→345 psi (+584%) — gathering backpressure event

Primary diagnosis

Stanhope/Ashcroft CTB cluster well. Static pressure trebled after April 14-17 across the entire network. This is a SYSTEM failure (compression/gathering), not 10 well failures. Individual well-level workups are the wrong first move.

Differential

Downstream compressor station offline or suction-choked
Sales line restriction/pigging issue
Plant reject / gas-quality shutdown rippling upstream

Immediate action

STOP well-level spend on this well. (1) Get comp-station SCADA pulled for the Kirby/Bayou compressor, (2) call midstream operator for line pressure history, (3) do not soap or plunge until gathering is restored — any chemistry burns before compression recovers is wasted.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Treat as gathering-system event, not well-level — see gathering_and_compression narrative	pending midstream	restoration of full 30d rate if gathering fixed	N/A (infrastructure)

CASE · 025 · DEV 40782 LOADING · AMBER

Ramsey Fields 2H Gas Lift

LOADING · target recovery +15 MCF/D · $1,575/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d MCF 333 vs 30d 355 (-6%)
DP 30d avg 55.6" H2O, delta +17%
Flow time 64% (slug/intermittent)
MaxDP 30d 163" (pressure spikes indicate head-gas/slugging)
Temp min 57F (paraffin cloud-point risk on east-TX black oil)
Battery 13.1V

Primary diagnosis

Classic liquid loading signature — FT sub-80, high MaxDP spikes, DP trending up while rate drops. Flowing temp below 60F in places is suspicious for paraffin onset — include solvent batch in any hot-oil treatment.

Differential

Liquid loading below Turner/Crenshaw critical velocity
Compressor suction loss on upstream unit (check comp runtime)
Choke plugging at sales meter — verify with independent pressure upstream

Immediate action

Pumper: (1) confirm FWHP at wellhead and compare to tubing head pressure at comp station, (2) soap 1 stick/AM for 7d, (3) photo wellhead gauges and record casing-to-tubing differential, (4) if well is on Stanhope/Ashcroft CTB, coordinate with gathering operator to confirm line pressure.

Diagnostics needed

FWHP at wellhead gauge (independent of SCADA SP)
Casing pressure shut-in test — Crenshaw critical velocity
Gas analysis (CO2, H2S, water) if not current
Coordinate downstream line pressure read from gathering operator

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick trial, 1 stick/day × 7 days	~$105/wk (sticks $15 ea)	+6-10 MCF/D if liquid-loading is real	<1 week at current prices
Plunger install if soap succeeds but intermittent persists	$8-12k capital + $150/mo service	+9-15 MCF/D steady-state	3-6 months
If CTB cluster event suspected, FIX GATHERING FIRST — soap/plunger wastes money if SP is elevated	$0	preserves chemistry budget	immediate

CASE · 026 · DEV 46037 LOW_FT · AMBER

HARMON-PIERCE GREGGTON SALES CHK

LOW_FT · target recovery +15 MCF/D · $1,575/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Flow time 51% — well is flowing <50% of each day (slug/intermittent)
Slug ratio MaxDP/avgDP = 14x — pressure surging
7d 49 MCF vs 30d 48 MCF
DP delta +2%

Primary diagnosis

Classic plunger-candidate signature: FT 51%, slug ratio 14x. Well is making rate in bursts. If reservoir still has energy (FWHP > critical), a plunger converts the slug regime into steady, and typically adds 20-50% on the remaining uplift.

Differential

Plunger-candidate (most likely given slug signature)
Gathering interference (cluster wells) — rule out first
Choke restriction / accumulated paraffin ring in tubing

Immediate action

Pumper FWHP reading + CP reading. If CP > FWHP by 50-150 psi during shut-in, well has Crenshaw margin and plunger is justified. Order plunger workup if economics clear $8k capex.

Diagnostics needed

Shut-in casing pressure test (Crenshaw criterion check)
GOR and water cut from nearest test
Paraffin cloud point from nearest gas/crude sample

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (conventional bar stock)	$8-12k cap + $150-250/mo optimization	+12-19 MCF/D steady	3-5 months
Soap-stick trial first to confirm liquid loading	$100-400 for 2-week trial	diagnostic clarity, minor uplift	<1 week

CASE · 027 · DEV 19828 DECLINING · RED

Markham Heirs #2 GL

DECLINING · target recovery +14 MCF/D · $1,470/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 1 vs 30d 29 MCF/D (-97%, ~-28 MCF/D lost)
DP delta -93%
Flow time 24%
Zero-flow days in window: 8
Temp min 50F — flag paraffin risk

Primary diagnosis

Low flow time (24%) with active decline. Likely either plunger-candidate (slug flow), stuck choke, or gathering header interference. Slug pattern visible in MaxDP spikes.

Differential

Plunger candidate — intermittent/slug flow regime
Wellhead choke too small after depletion
Upstream separator/tank dump cycles interfering

Immediate action

Pumper visit, review choke size + casing pressure, soap-stick trial, candidate for plunger workup.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+8-17 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+14-22 MCF/D	3-6 months
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+5-11 MCF/D if paraffin-restricted	1-3 months

CASE · 028 · DEV 19845 DECLINING · AMBER

Lyman Sales Chk

DECLINING · target recovery +14 MCF/D · $1,470/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 73 vs 30d 101 MCF/D (-28%, ~-28 MCF/D lost)
DP delta -55%
Flow time 96%

Primary diagnosis

Moderate decline (-28%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+8-16 MCF/D if mechanical	1-2 weeks

CASE · 029 · DEV 19873 DECLINING · AMBER

Stanhope #3 Alloc

DECLINING · target recovery +14 MCF/D · $1,470/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 36 vs 30d 60 MCF/D (-40%, ~-24 MCF/D lost)
DP delta -62%
Flow time 70%
Zero-flow days in window: 3
SP creep 57→403 psi (+608%) — gathering backpressure event

Primary diagnosis

Stanhope/Ashcroft CTB cluster well. Static pressure trebled after April 14-17 across the entire network. This is a SYSTEM failure (compression/gathering), not 10 well failures. Individual well-level workups are the wrong first move.

Differential

Downstream compressor station offline or suction-choked
Sales line restriction/pigging issue
Plant reject / gas-quality shutdown rippling upstream

Immediate action

STOP well-level spend on this well. (1) Get comp-station SCADA pulled for the Kirby/Bayou compressor, (2) call midstream operator for line pressure history, (3) do not soap or plunge until gathering is restored — any chemistry burns before compression recovers is wasted.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Treat as gathering-system event, not well-level — see gathering_and_compression narrative	pending midstream	restoration of full 30d rate if gathering fixed	N/A (infrastructure)

CASE · 030 · DEV 38841 DECLINING · YELLOW

Ridgewood South 1H

DECLINING · target recovery +13 MCF/D · $1,365/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 128 vs 30d 154 MCF/D (-17%, ~-26 MCF/D lost)
DP delta -2%
Flow time 98%

Primary diagnosis

Moderate decline (-17%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+7-15 MCF/D if mechanical	1-2 weeks

CASE · 031 · DEV 57324 DECLINING · RED

Barrett #1

DECLINING · target recovery +13 MCF/D · $1,365/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 0 vs 30d 25 MCF/D (-100%, ~-25 MCF/D lost)
DP delta -100%
Flow time 50%
Zero-flow days in window: 8

Primary diagnosis

Moderate decline (-100%). Multiple plausible causes — could be natural decline + minor mechanical issue. Not emergency. Ground-truth with pumper visit within 1 week.

Differential

Natural depletion (normal Cotton Valley / Travis Peak decline curve)
Rising water cut — check battery gauge rows
Partial paraffin restriction in tubing

Immediate action

Pumper check — tubing/casing pressures, battery/stock tanks, visual inspection of well hook-up.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+7-15 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+12-20 MCF/D	3-6 months

CASE · 032 · DEV 19882 DECLINING · YELLOW

Westbrook #1 Alloc

DECLINING · target recovery +12 MCF/D · $1,260/mo conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 81 vs 30d 101 MCF/D (-20%, ~-21 MCF/D lost)
DP delta -55%
Flow time 73%
Zero-flow days in window: 4
SP creep 62→377 psi (+505%) — gathering backpressure event

Primary diagnosis

Stanhope/Ashcroft CTB cluster well. Static pressure trebled after April 14-17 across the entire network. This is a SYSTEM failure (compression/gathering), not 10 well failures. Individual well-level workups are the wrong first move.

Differential

Downstream compressor station offline or suction-choked
Sales line restriction/pigging issue
Plant reject / gas-quality shutdown rippling upstream

Immediate action

STOP well-level spend on this well. (1) Get comp-station SCADA pulled for the Kirby/Bayou compressor, (2) call midstream operator for line pressure history, (3) do not soap or plunge until gathering is restored — any chemistry burns before compression recovers is wasted.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Treat as gathering-system event, not well-level — see gathering_and_compression narrative	pending midstream	restoration of full 30d rate if gathering fixed	N/A (infrastructure)

CASE · 033 · DEV 38898 DECLINING · RED

STANFORD 005

DECLINING · target recovery +11 MCF/D · $1,155/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 1 vs 30d 22 MCF/D (-97%, ~-21 MCF/D lost)
DP delta -77%
Flow time 7%
Zero-flow days in window: 16

Primary diagnosis

Well has 16+ days of zero flow and -97% MCF loss. Either shut-in, choke-plugged, RTU value stuck, or terminal load-up with head-gas stalling lift. Need eyes on-site before any action.

Differential

Shut-in (planned or tripped safety valve)
Choke/needle valve plugged with paraffin or scale
Loaded column of water + gas — needs unload cycle
Meter/orifice plate fouled (compare with chart meter if available)

Immediate action

Pumper visit today: check wellhead gauges, cycle the choke, unload any obvious liquid column, verify FWHP and casing pressure. If casing > tubing by >200 psi, loaded column is confirmed.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Soap-stick + choke optimization trial (2 weeks)	~$250-400	+6-12 MCF/D if mechanical	1-2 weeks
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+10-16 MCF/D	3-6 months

CASE · 034 · DEV 107211 DECLINING · RED

R.C. Cranbrook #1

DECLINING · target recovery +7 MCF/D · $735/mo conf: medium

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

7d 3 vs 30d 17 MCF/D (-80%, ~-14 MCF/D lost)
DP delta -64%
Flow time 6%
Zero-flow days in window: 5
Temp min 52F — flag paraffin risk

Primary diagnosis

Low flow time (6%) with active decline. Likely either plunger-candidate (slug flow), stuck choke, or gathering header interference. Slug pattern visible in MaxDP spikes.

Differential

Plunger candidate — intermittent/slug flow regime
Wellhead choke too small after depletion
Upstream separator/tank dump cycles interfering

Immediate action

Pumper visit, review choke size + casing pressure, soap-stick trial, candidate for plunger workup.

Diagnostics needed

Pumper visit — FWHP, CP, battery gauges
Compare wellhead gauge to SCADA SP (delta = gathering loss)
Gas analysis if >12mo old

Fix options & ROI

Action	Cost	Expected	Payback
Plunger lift install (after soap confirms liquid)	$8-12k capital, $150/mo	+6-11 MCF/D	3-6 months
Hot-oil + paraffin solvent batch, then continuous paraffin inhibitor	$2-3k batch + $250-400/mo continuous	+5-5 MCF/D if paraffin-restricted	1-3 months

CASE · 035 · DEV 40765 BATTERY · RED

Lyman 3

BATTERY · target recovery — · — conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Spot battery 8.24V — below 11.5V threshold
Driver NX_Floboss — RTU still reporting for now
Latest MCF 65.36059, 30d 54.03

Primary diagnosis

RTU at risk of going dark. At 8.2V, solar+battery system is either (a) battery at end of life (3-5yr typical), (b) solar panel shaded / damaged / pointing wrong direction, (c) charge controller failing. Once below ~10.5V the modem resets and we lose visibility.

Differential

Battery at EOL (most common on aging deployments)
Solar shading (recent tree growth, debris)
Charge controller or wiring failure
New load added (e.g., second solenoid) exceeds solar budget

Immediate action

Pumper inspection this week — clean panel, visually check battery bulge/leak, measure panel Voc on a sunny day. Order 12V 100Ah AGM as pre-emptive replacement (~$250).

Diagnostics needed

Battery voltage at dusk and dawn
Solar panel Voc and Isc
Load current

Fix options & ROI

Action	Cost	Expected	Payback
Replace battery (AGM 12V 100Ah)	$250 parts + $150 labor	1-2 days visibility restored, 3-5yr service	N/A — prevents loss of diagnostic ability
Panel clean + alignment	$100 labor	may restore if battery still good	N/A

CASE · 036 · DEV 44761 BATTERY · AMBER

Roundtable Discharge

BATTERY · target recovery — · — conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

Spot battery 11.49V — below 11.5V threshold
Driver NX_Totalflow — RTU still reporting for now
Latest MCF 0.0, 30d 121.42

Primary diagnosis

RTU at risk of going dark. At 11.5V, solar+battery system is either (a) battery at end of life (3-5yr typical), (b) solar panel shaded / damaged / pointing wrong direction, (c) charge controller failing. Once below ~10.5V the modem resets and we lose visibility.

Differential

Battery at EOL (most common on aging deployments)
Solar shading (recent tree growth, debris)
Charge controller or wiring failure
New load added (e.g., second solenoid) exceeds solar budget

Immediate action

Pumper inspection this week — clean panel, visually check battery bulge/leak, measure panel Voc on a sunny day. Order 12V 100Ah AGM as pre-emptive replacement (~$250).

Diagnostics needed

Battery voltage at dusk and dawn
Solar panel Voc and Isc
Load current

Fix options & ROI

Action	Cost	Expected	Payback
Replace battery (AGM 12V 100Ah)	$250 parts + $150 labor	1-2 days visibility restored, 3-5yr service	N/A — prevents loss of diagnostic ability
Panel clean + alignment	$100 labor	may restore if battery still good	N/A

CASE · 037 · DEV 19852 STALE_RTU · AMBER

Baxter #1 Alloc

STALE_RTU · target recovery — · — conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

SCADA silent 12 days — data stops 2026-04-11
Pre-silence 30d avg 41.66 MCF/D

Primary diagnosis

Telecom / RTU comms failure. Likely candidates: Totalflow cellular modem failed, solar charge controller degraded, or ABB unit stopped logging. NOT a production event per se — but every day dark costs us diagnosis ability on a real well.

Differential

Cell modem — most common (replace ~$600)
Solar panel shaded/damaged or charge controller dead
Battery reached end of life — check last battery_v reading
Totalflow firmware hung — power cycle fixes

Immediate action

Dispatch I&E technician. Confirm power and comms. Power-cycle first; if still dark, pull modem SN and verify with Verizon/AT&T that SIM is active.

Diagnostics needed

Last successful poll timestamp
Modem RSSI reading
Battery voltage at site

Fix options & ROI

Action	Cost	Expected	Payback
Field I&E visit (power-cycle, check modem)	$200-400 truck roll	~60% first-visit restore rate	immediate — restores visibility
Cell modem swap	$600-900 parts + $200 labor	permanent fix	N/A (infrastructure)

CASE · 038 · DEV 38873 STALE_RTU · AMBER

HARTSFIELD #1

STALE_RTU · target recovery — · — conf: high

MCF · 30 day0–peak

Observed

SCADA silent 4 days — data stops 2026-04-19
Pre-silence 30d avg 0.0 MCF/D

Primary diagnosis

Telecom / RTU comms failure. Likely candidates: Totalflow cellular modem failed, solar charge controller degraded, or ABB unit stopped logging. NOT a production event per se — but every day dark costs us diagnosis ability on a real well.

Differential

Cell modem — most common (replace ~$600)
Solar panel shaded/damaged or charge controller dead
Battery reached end of life — check last battery_v reading
Totalflow firmware hung — power cycle fixes

Immediate action

Dispatch I&E technician. Confirm power and comms. Power-cycle first; if still dark, pull modem SN and verify with Verizon/AT&T that SIM is active.

Diagnostics needed

Last successful poll timestamp
Modem RSSI reading
Battery voltage at site

Fix options & ROI

Action	Cost	Expected	Payback
Field I&E visit (power-cycle, check modem)	$200-400 truck roll	~60% first-visit restore rate	immediate — restores visibility
Cell modem swap	$600-900 parts + $200 labor	permanent fix	N/A (infrastructure)

CASE · 039 · DEV 38884 STALE_RTU · AMBER

CLEMENT 006

STALE_RTU · target recovery — · — conf: high

MCF · 30 day0–peak

Observed

SCADA silent 6 days — data stops 2026-04-17
Pre-silence 30d avg 0.0 MCF/D

Primary diagnosis

Telecom / RTU comms failure. Likely candidates: Totalflow cellular modem failed, solar charge controller degraded, or ABB unit stopped logging. NOT a production event per se — but every day dark costs us diagnosis ability on a real well.

Differential

Cell modem — most common (replace ~$600)
Solar panel shaded/damaged or charge controller dead
Battery reached end of life — check last battery_v reading
Totalflow firmware hung — power cycle fixes

Immediate action

Dispatch I&E technician. Confirm power and comms. Power-cycle first; if still dark, pull modem SN and verify with Verizon/AT&T that SIM is active.

Diagnostics needed

Last successful poll timestamp
Modem RSSI reading
Battery voltage at site

Fix options & ROI

Action	Cost	Expected	Payback
Field I&E visit (power-cycle, check modem)	$200-400 truck roll	~60% first-visit restore rate	immediate — restores visibility
Cell modem swap	$600-900 parts + $200 labor	permanent fix	N/A (infrastructure)

CASE · 040 · DEV 17487 STALE_RTU · AMBER

Wolford 2-4-5 CK

STALE_RTU · target recovery — · — conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

SCADA silent 7 days — data stops 2026-04-16
Pre-silence 30d avg 94.99 MCF/D

Primary diagnosis

Telecom / RTU comms failure. Likely candidates: Totalflow cellular modem failed, solar charge controller degraded, or ABB unit stopped logging. NOT a production event per se — but every day dark costs us diagnosis ability on a real well.

Differential

Cell modem — most common (replace ~$600)
Solar panel shaded/damaged or charge controller dead
Battery reached end of life — check last battery_v reading
Totalflow firmware hung — power cycle fixes

Immediate action

Dispatch I&E technician. Confirm power and comms. Power-cycle first; if still dark, pull modem SN and verify with Verizon/AT&T that SIM is active.

Diagnostics needed

Last successful poll timestamp
Modem RSSI reading
Battery voltage at site

Fix options & ROI

Action	Cost	Expected	Payback
Field I&E visit (power-cycle, check modem)	$200-400 truck roll	~60% first-visit restore rate	immediate — restores visibility
Cell modem swap	$600-900 parts + $200 labor	permanent fix	N/A (infrastructure)

CASE · 041 · DEV 19846 STALE_RTU · AMBER

Halsey Sales Chk

STALE_RTU · target recovery — · — conf: high

MCF · 30 day0–peak

DP · inH₂O · 30 dayamber

Observed

SCADA silent 10 days — data stops 2026-04-13
Pre-silence 30d avg 35.24 MCF/D

Primary diagnosis

Telecom / RTU comms failure. Likely candidates: Totalflow cellular modem failed, solar charge controller degraded, or ABB unit stopped logging. NOT a production event per se — but every day dark costs us diagnosis ability on a real well.

Differential

Cell modem — most common (replace ~$600)
Solar panel shaded/damaged or charge controller dead
Battery reached end of life — check last battery_v reading
Totalflow firmware hung — power cycle fixes

Immediate action

Dispatch I&E technician. Confirm power and comms. Power-cycle first; if still dark, pull modem SN and verify with Verizon/AT&T that SIM is active.

Diagnostics needed

Last successful poll timestamp
Modem RSSI reading
Battery voltage at site

Fix options & ROI

Action	Cost	Expected	Payback
Field I&E visit (power-cycle, check modem)	$200-400 truck roll	~60% first-visit restore rate	immediate — restores visibility
Cell modem swap	$600-900 parts + $200 labor	permanent fix	N/A (infrastructure)

CASE · 042 · DEV 50149 ZERO_FLOW · AMBER

BEAUFORT GU 3H

ZERO_FLOW · target recovery — · — conf: low

MCF · 30 day0–peak

Observed

30 days of zero MCF
Back-flow days 0, bf_avg 0.0
Driver NX_Totalflow — RTU is reporting, just showing zero

Primary diagnosis

Shut-in well or failed well. 30 days of zero is beyond any normal downtime. Need to know from Meridian: is this planned (SIPP test, regulatory hold, offset frac protection) or unplanned (mechanical failure, tubing leak, tree issue)?

Differential

Planned shut-in (frac protection, SIPP test, regulatory)
Mechanical failure (tubing leak, wellhead leak, downhole restriction)
Pumper mis-routed (well never gets visited)
Abandoned / de facto P&A candidate

Immediate action

Confirm intent with Meridian ops. If unplanned, workover evaluation.

Diagnostics needed

FWHP and CP at wellhead
Tubing integrity test
Last completion/workover date

Fix options & ROI

Action	Cost	Expected	Payback
Ground-truth with pumper	$0	diagnosis	N/A
If mechanical, workover evaluation	$30-80k	rate restoration	dependent on pre-shut-in rate

CASE · 043 · DEV 49977 ZERO_FLOW · AMBER

Holloway #1 Injection

ZERO_FLOW · target recovery — · — conf: low

MCF · 30 day0–peak

Observed

30 days of zero MCF
Back-flow days 0, bf_avg 0.0
Driver NX_Totalflow — RTU is reporting, just showing zero

Primary diagnosis

Shut-in well or failed well. 30 days of zero is beyond any normal downtime. Need to know from Meridian: is this planned (SIPP test, regulatory hold, offset frac protection) or unplanned (mechanical failure, tubing leak, tree issue)?

Differential

Planned shut-in (frac protection, SIPP test, regulatory)
Mechanical failure (tubing leak, wellhead leak, downhole restriction)
Pumper mis-routed (well never gets visited)
Abandoned / de facto P&A candidate

Immediate action

Confirm intent with Meridian ops. If unplanned, workover evaluation.

Diagnostics needed

FWHP and CP at wellhead
Tubing integrity test
Last completion/workover date

Fix options & ROI

Action	Cost	Expected	Payback
Ground-truth with pumper	$0	diagnosis	N/A
If mechanical, workover evaluation	$30-80k	rate restoration	dependent on pre-shut-in rate

CASE · 044 · DEV 13610 ZERO_FLOW · AMBER

Echo Bradford 2-1H

ZERO_FLOW · target recovery — · — conf: low

MCF · 30 day0–peak

Observed

30 days of zero MCF
Back-flow days 0, bf_avg 0.0
Driver NX_Totalflow — RTU is reporting, just showing zero

Primary diagnosis

Shut-in well or failed well. 30 days of zero is beyond any normal downtime. Need to know from Meridian: is this planned (SIPP test, regulatory hold, offset frac protection) or unplanned (mechanical failure, tubing leak, tree issue)?

Differential

Planned shut-in (frac protection, SIPP test, regulatory)
Mechanical failure (tubing leak, wellhead leak, downhole restriction)
Pumper mis-routed (well never gets visited)
Abandoned / de facto P&A candidate

Immediate action

Confirm intent with Meridian ops. If unplanned, workover evaluation.

Diagnostics needed

FWHP and CP at wellhead
Tubing integrity test
Last completion/workover date

Fix options & ROI

Action	Cost	Expected	Payback
Ground-truth with pumper	$0	diagnosis	N/A
If mechanical, workover evaluation	$30-80k	rate restoration	dependent on pre-shut-in rate

CASE · 045 · DEV 38846 ZERO_FLOW · YELLOW

SALADO CREEK 011

ZERO_FLOW · target recovery — · — conf: high

MCF · 30 day0–peak

Observed

Forward MCF = 0, but back-flow 30/30 days @ ~100 MCF/D avg
Classification is misleading — this meter is moving gas, just in reverse direction

Primary diagnosis

Not a zero-flow well. This is either (a) a gas-lift buyback meter dispositioning injection gas, (b) a meter piped backwards, or (c) a plant-side meter that inverted sales direction. WellRX zero-flow classifier should be patched to treat high-BF / zero-FF as its own class.

Differential

Gas lift injection gas buyback meter
Installed backwards
Plant-level inverted flow

Immediate action

Confirm with engineering — this well does not need a workover; it's a data issue.

Diagnostics needed

Meter orientation verification
AGA orifice plate direction check

Fix options & ROI

Action	Cost	Expected	Payback
Patch WellRX classifier to treat BF=100 as dedicated 'INJECTION' class	software change	removes false ZERO_FLOW alarm	immediate

CASE · 046 · DEV 46035 ZERO_FLOW · AMBER

HARMON PIERCE GU 001

ZERO_FLOW · target recovery — · — conf: low

MCF · 30 day0–peak

Observed

30 days of zero MCF
Back-flow days 0, bf_avg 0.0
Driver NX_Totalflow — RTU is reporting, just showing zero

Primary diagnosis

Shut-in well or failed well. 30 days of zero is beyond any normal downtime. Need to know from Meridian: is this planned (SIPP test, regulatory hold, offset frac protection) or unplanned (mechanical failure, tubing leak, tree issue)?

Differential

Planned shut-in (frac protection, SIPP test, regulatory)
Mechanical failure (tubing leak, wellhead leak, downhole restriction)
Pumper mis-routed (well never gets visited)
Abandoned / de facto P&A candidate

Immediate action

Confirm intent with Meridian ops. If unplanned, workover evaluation.

Diagnostics needed

FWHP and CP at wellhead
Tubing integrity test
Last completion/workover date

Fix options & ROI

Action	Cost	Expected	Payback
Ground-truth with pumper	$0	diagnosis	N/A
If mechanical, workover evaluation	$30-80k	rate restoration	dependent on pre-shut-in rate

Well	Dev	Class	Reason	MCF/D	Δ 7/30	Pumper check
Henry R Shaw #3 Alloc	19866	DECLINING	Declining ~27% but low absolute loss (<20 MCF/D).	25.541231	-27.4%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Lockhart #1 Alloc	19848	DECLINING	Declining ~16% but low absolute loss (<20 MCF/D).	61.000004	-15.9%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
ORION 001	38887	DECLINING	Declining ~23% but low absolute loss (<20 MCF/D).	0.004206276	-23.3%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
GALLATIN 002	38857	DECLINING	Declining ~69% but low absolute loss (<20 MCF/D).	0.0	-69.2%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Barrett #3	57325	DECLINING	Declining ~100% but low absolute loss (<20 MCF/D).	0.0	-100.0%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Rockwell Meadows GU #4	45992	DECLINING	Declining ~36% but low absolute loss (<20 MCF/D).	0.0	-36.2%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Ledford 1	105657	DECLINING	Declining ~24% but low absolute loss (<20 MCF/D).	5.2564836	-24.0%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Warren GU 1-4	111034	DECLINING	Declining ~30% but low absolute loss (<20 MCF/D).	0.0	-30.2%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Ramsey Fields Buy Back	40533	DECLINING	Declining ~100% but low absolute loss (<20 MCF/D).	0.0	-100.0%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Ashcroft #1 Alloc	19871	DECLINING	Declining ~100% but low absolute loss (<20 MCF/D).	0.0	-100.0%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Amelia Kirk #2H	45996	DECLINING	Declining ~100% but low absolute loss (<20 MCF/D).	0.0	-100.0%	Pumper routine visit — FWHP, CP, battery, water gauges. No spend until trend continues.
Cogswell #1	107225	LOW_FT	Low FT (7%) but <50 MCF/D — uplift too small for capex plunger today.	0.0	72.5%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
Stanhope #1 Alloc	19868	LOW_FT	Low FT (49%) but <50 MCF/D — uplift too small for capex plunger today.	71.14637	21.7%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
BRENNER S R 002	46002	LOW_FT	Low FT (18%) but <50 MCF/D — uplift too small for capex plunger today.	24.390127	-3.5%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
Kirby #3 Alloc	19872	LOW_FT	Low FT (44%) but <50 MCF/D — uplift too small for capex plunger today.	21.260355	-12.4%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
WINSLOW G H GU 005	46038	LOW_FT	Low FT (29%) but <50 MCF/D — uplift too small for capex plunger today.	17.624361	-10.8%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
Winthrop 1	40019	LOW_FT	Low FT (38%) but <50 MCF/D — uplift too small for capex plunger today.	12.873819	-11.4%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
HENDERSON NORTH	38880	LOW_FT	Low FT (0%) but <50 MCF/D — uplift too small for capex plunger today.	0.0	75.8%	Soap-stick trial 2 weeks. If rate responds, revisit plunger economics.
BRADFORD ECHO 006H	46027	OFFLINE	RTU dark 14d but had 17 days of data in window — real well, real outage.	0	None%	I&E truck roll to power-cycle RTU; confirm modem / solar.
Gallatin-West Sales Chk	6138	OFFLINE	RTU dark 18d but had 13 days of data in window — real well, real outage.	0	None%	I&E truck roll to power-cycle RTU; confirm modem / solar.
Lamar #1H	26525	OFFLINE	RTU dark 18d but had 13 days of data in window — real well, real outage.	0	None%	I&E truck roll to power-cycle RTU; confirm modem / solar.
WESLEY 002	46031	OFFLINE	RTU dark 17d but had 14 days of data in window — real well, real outage.	0	None%	I&E truck roll to power-cycle RTU; confirm modem / solar.

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The Stanhope & Ashcroft CTB Gathering Event

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Chemistry Program

Artificial-Lift Strategy

Top-Ten Action Stack · 90-Day Plan

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Data Quality · What Is Not Diagnosable Here